CHP Interconnection Equipment Analysis

Transcription

1 Gas Technology Institute 1700 S. Mount Prospect Rd. Des Plaines, Illinois FINAL REPORT GTI PROJECT NUMBER 21790, UTD 2.15.O CHP Interconnection Equipment Analysis Report Issued: June 2016 Prepared For: Dan LeFevers Senior Development Leader Energy Projects and Programs (202) Prepared By: CDH Energy Corp 2695 Bingley Road Cazenovia, New York GTI Technical Contact: Tim Kingston Senior Engineer Contributors: Hugh Henderson Carina Paton Dan LeFevers

2 Legal Notice This information was prepared by Gas Technology Institute ( GTI ) for Utilization Technology Development. Neither GTI, the members of GTI, the Sponsor(s), nor any person acting on behalf of any of them: a. Makes any warranty or representation, express or implied with respect to the accuracy, completeness, or usefulness of the information contained in this report, or that the use of any information, apparatus, method, or process disclosed in this report may not infringe privately-owned rights. Inasmuch as this project is experimental in nature, the technical information, results, or conclusions cannot be predicted. Conclusions and analysis of results by GTI represent GTI's opinion based on inferences from measurements and empirical relationships, which inferences and assumptions are not infallible, and with respect to which competent specialists may differ. b. Assumes any liability with respect to the use of, or for any and all damages resulting from the use of, any information, apparatus, method, or process disclosed in this report; any other use of, or reliance on, this report by any third party is at the third party's sole risk. c. The results within this report relate only to the items tested. CHP Interconnection Equipment Analysis Page i

3 Table of Contents Legal Notice... i Table of Contents...ii Table of Figures... iv Table of Tables... v Executive Summary... 1 Common Utility Concerns... 1 Technical Findings... 2 Non-Technical Findings... 3 Conclusion... 4 Next Steps... 5 Introduction... 6 Study Approach... 6 Organization of this Report... 6 Regional Interconnection Standards and Procedures... 7 Overview... 7 Federal Energy Regulatory Commission (FERC)... 9 California Minnesota New York Ontario Conclusions Next Steps References Appendix A Background and Common Terms Distributed Generation Onsite Generation Electrical Connection Options Parallel Operation Options Tariff (or Compensation) Options Types of Generators Protective Relays Isolation and Protection Devices Transformers Electrical Standards Appendix B Common Utility Concerns with Electrical Interconnection Utility Distribution Systems Protection Needs for Distributed Generation Appendix C Interviewed Stakeholders CHP Interconnection Equipment Analysis Page ii

4 Appendix D Equipment Catalog CHP Packages Protective Relays Appendix E Web Resources for Distributed Generation Interconnection CHP Interconnection Equipment Analysis Page iii

5 Table of Figures Figure 1 U.S. States with Distributed Generation Interconnection Guidelines (yellow) and Standards (green) (DSIRE 2015)... 7 Figure 2 Distributed Generation Interconnection Chart for California Figure 3 Maximum Capacity for Interconnection Application Processes in New York, as Reported by the Electric Utilities (NYSERDA 2015) Figure 4 - Radial Distribution System (Modified from CEC 2003 and ConEd 2012) Figure 5 Network Distribution System (Modified from CEC 2003 and ConEd 2012) CHP Interconnection Equipment Analysis Page iv

6 Table of Tables Table 1 Maximum System Capacity Covered by State and Provincial Interconnection Standards... 8 Table 2 Interconnection Standard Components... 9 Table 3 Eligibility for FERC SGIP Pathways Table 4 FERC SGIP Fast Track Eligibility for Inverter-Based Systems Table 5 Large Investor-Owned Electric Utilities in California Table 6 Required Protective Functions for PG&E and SCE Interconnections Table 7 Industrial-Grade Relays Approved by PG&E (PG&E 2003) Table 8 Utility-Grade Relays Approved by PG&E (PG&E 2003) Table 9 WDAT Interconnection Processes in California Table 10 Rule 21 Interconnection Processes in California Table 11 Interconnection Categories in Minnesota (MPUC 2004) Table 12 Investor-Owned Electric Utilities in Minnesota Table 13 Protective Requirements by Interconnection Type in Minnesota (MPUC 2004) Table 14 Investor-Owned Electric Utilities in New York State Table 15 Minimum Protective Requirements in NY SIR Table 16 Utility-grade Relay Specifications in the New York Standard Interconnection Requirements Table 17 Non-Inverter Interconnection Equipment Certified by NY PSC (NY PSC 2015d) Table 18 Minimum Protective Functions Required for Distributed Generation Connected to Hydro One Distribution System Table 19 Selection of Standard Devices Specified in ANSI/IEEE C Table 20 Commonly Referenced Standards in Standard Interconnection Requirements CHP Interconnection Equipment Analysis Page v

7 Executive Summary Electricity supply resources are becoming more decentralized, with an increasing number of distributed generation resources being installed behind customer meters to serve some or the entire customer load. Combined heat and power (CHP) in particular is an attractive application because of its energy efficiency and low carbon emissions. Low natural gas prices make CHP even more economically promising and new opportunities may exist for deployment in the commercial and industrial sectors. Many barriers remain for further expansion of CHP. One important barrier is the non-uniformity of regulations surrounding interconnection to the grid. This report identifies and compares common North American interconnection standards, practices and issues for onsite generators in several representative electric utility regions. The report explains common concerns that electric utilities have with interconnected distributed generation, and reviews common behind-the-meter equipment such as generators, inverters and electrical protection devices used to ensure safe operation. The report also explores the administrative and technical differences between interconnecting solar photovoltaics (PV) compared to CHP systems. Standard interconnection requirements exist at the national, state/province, and utility levels. In the U.S., they are based on IEEE 1547 Standard for Interconnecting Distributed Resources with Electric Power Systems. IEEE 1547 was approved as an American National Standard in 2003 and continues to be updated as the amount of distributed generation interconnected with the electrical grid increases and as new technology is developed. The equivalent in Canada is CAN/CSA C22.3 No. 9 Interconnection of Distributed Resources and Electricity Supply Systems and CAN/CSA C22.2 No. 257 Interconnecting Inverter-Based Micro-Distributed Resources to Distribution Systems. The intention of IEEE 1547 and CAN/CSA C22.2 and C22.3 is for consistent performance, safety, testing, and maintenance requirements for distributed generation interconnections across jurisdictions. However, in practice, the interpretation and application of the standards vary from utility to utility and state to state. As a result, CHP projects still face significant delays and costs. The focus of this report is distributed generation on the customer-side of the meter that operates in parallel with the utility grid. The information presented here is based on review of regulatory and utility documents as well as interviews with industry experts. Common Utility Concerns Utilities are concerned about how distributed generation might affect utility or customer-owned equipment and worker safety during normal conditions and grid outages. In general, large generators pose a greater concern to a utility and thus have more stringent protection requirements than small generators (i.e. less than 50kW). Utility concerns include: Islanding When electric utility service is lost, the generator must cease to energize the local power system within a few seconds and remain disconnected until electric service has been re-established and stable for a specified number of minutes. It is important that the generator shut down before utility-side reclosers attempt to re-energize the grid. Generally, small generators will immediately shut down on voltage, frequency, and over-current faults when overloaded. With large generators, there is a small chance that the generator capacity and electric load will remain in perfect balance so that operation can continue. With large systems, active anti-islanding controls are required to detect this condition. Islanding protection features are standard functions within most protective relays and many inverters. Fault Current Onsite generators add to the existing fault current at a utility substation, beyond what the utility-side protective devices were designed to withstand. Synchronous generators pose the greatest concern since they can contribute larger and more sustained fault currents than induction generators or inverters. Therefore, the utility may not allow synchronous generators, or they may require utility-side or customer-side changes to mitigate or protect against the fault current. Utility-generator Synchronization The electricity produced by the generator must match the frequency, phase angle, and voltage of the utility power. Protective relays and generator controls confirm CHP Interconnection Equipment Analysis Page 1

8 synchronization prior to paralleling with the grid and detect any loss of synchronization during gridparallel operation. Power Quality Ground currents, voltage flicker, harmonic distortion, power system stability, and increased fault duty on utility circuit breakers could have a detrimental impact on the utility power system. Voltage dip and fluctuations are also of concern during generator startup, particularly for induction generators. IEEE 1547 and 519 specify power quality requirements, and the utility may also specify requirements. Voltage Regulation Traditional utility-side step voltage regulators are designed for power flowing from the substation to the load, and may not work correctly if a customer generator exporting power causes the power to flow in the reverse direction. Although many modern voltage regulators can now operate under reverse power conditions, old regulators still exist in the power system and might be expected to remain in service for several years to come. Therefore, the utility may require protection that prohibits reverse power flow (into the utility grid from the generator) if older voltage regulators are in place. Redundancy Utilities commonly require redundancy to ensure the generator is still automatically disconnected from the utility system if one piece of protection equipment fails. This leads to requirements for redundant protections that the customer must purchase. Radial vs. Network Distribution Most distribution systems are radial, with primary lines radiating from the substation to the transformers and secondary lines radiating from there to the customers. Since a fault interrupts power to all downline customers in a radial system, islanding can occur if any of the interrupted customers continue to generate power. On the other hand, high-density areas such as large cities (e.g., Manhattan) and even some downtown areas of medium-sized cities are usually network distribution systems. These systems have multiple feeders providing electricity to the secondary distribution grid, allowing power to continue to flow even if one feeder fails. While this does increase power reliability, the network protectors that prohibit power from flowing back to the substation feeders can restrict the amount of distributed generation that can be exported onto the network. Technical Findings The following summarize key technical hurdles observed by CHP installers interviewed for this report: Synchronous Generators It is generally more difficult to interconnect synchronous generators than induction generators or inverters. Often, more protective functions and other equipment are required to ensure grid synchronization and generator fault current will not contribute to a utility grid fault. Synchronous generators are more easily integrated with radial than network distribution systems. However, even if the addition of a synchronous generator may seem possible (e.g., system maps from the utility show sufficient available fault current at substations), the utility may not permit the interconnection without requiring the customer pay for costly upgrades to the local utility grid. Inverters Inverters are widely used with microturbines and reciprocating engines to ease interconnection issues. Inverter costs are about $800 per kw, but are steadily decreasing. In some utility territories, inverters combined with rotating generators do receive the same treatment as inverters combined with solar PV. However, this is not universal, and some utility territories still require additional protection. Even so, adding an inverter to a rotating generator does allow them to be installed in some locations that would otherwise not be permitted or practical. It is generally much easier to interconnect inverters than other interconnection technologies, especially if they are UL 1741 certified and/or are on the utility or public service commission list of certified devices. In some cases, particularly for smaller inverter systems used with solar PV, the utility does not require any protection in addition to capabilities integral to the inverter. Certified Equipment Lists It is an advantage for generating equipment to be listed on a utility or public utility commission list of certified equipment. In some jurisdictions, this enables the project to go through a faster and cheaper interconnection application and approval process than if unlisted. However, CHP Interconnection Equipment Analysis Page 2

9 in New York and California where certification lists apply, certification is limited to systems with inverters. Additional Protective Relays It is common for CHP generator packages to have onboard features within the controls that provide active anti-islanding protection and other grid interconnection features. Yet, even if the generator package has been tested and certified to applicable standards, utilities often still require additional protective devices. Adding utility protection requirements to a generator system is costly. For example, while protective relays alone are inexpensive, a great deal of supplemental equipment is required, such as current transformers, additional wiring and cabinetry, battery power supply, and subsequent certification testing. Most CHP installations use one of a small selection of protective relays. Relays in common use are the Beckwith 3410 and 3410A, and SEL 351 and 751. Reverse Power Protection and Import Set Points One of the main reasons that protective relays are needed is for reverse power protection. One CHP vendor pointed out that a less stringent reverse power protection approach could meet the utility goals of limited power export at a much lower cost. For instance, using a power transducer with a signal output tied to the generator controls to indicate when exporting occurs and shut down the unit within seconds (or allow generator controls sufficient time to reduce generator output). Instead, utilities require costly protective relay additions with current settings that shut the generator down after two seconds of reverse power flow. This two second requirement for CHP generators is onerous since in many cases, hundreds, if not more, solar PV systems are allowed to export significant amounts of power under net metering arrangements. Less stringent reverse power protection would also allow for lower import set points. Stringent reverse power protections require larger buffers on import power set points, which limit the amount of load that can be met by the onsite generator. Less stringent reverse power settings would allow more electric load to be served by the generator and thus improve the overall financial viability of the project. Lockable Disconnects All utilities require visible, lockable disconnects on the CHP system. However, the required location of disconnects vary. Some utilities require disconnects to be outside (easily accessible to line maintenance crews and fire service), while others allow them to be in electrical rooms. Installing outdoor disconnects can be costly compared to indoor disconnects and CHP installers question their necessity. In New York, CHP installers have observed installations where disconnects were never used, even during prolonged outages and widespread line maintenance, such as those associated with Hurricane Sandy. Non-Technical Findings The following are key non-technical hurdles that in many cases were more concerning for the stakeholders than the technical hurdles described above: Preferential Treatment for Certain Technologies CHP rarely receives the same special treatment given to renewable technologies, despite offering significant greenhouse gas emissions reductions and efficiency benefits. For example, CHP is eligible for net energy metering in only about 20 states; and most of those states have system and aggregate capacity limitations. In Massachusetts CHP systems only up to 60 kw are eligible for net metering, while other specified renewable technologies up to 2 MW are eligible. As a result, CHP projects have higher costs, more elaborate approval processes, and more difficulty exporting electricity than renewable energy projects. It is more difficult to get approval from utilities and other regulatory agencies to export electricity to the grid with CHP than other distributed renewable technology. CHP developers have expressed a regulatory and programmatic barrier rather than a technological barrier. The barrier exists even for inverter-based CHP technology that is technically the same as inverter-based PV and wind technology. CHP Interconnection Equipment Analysis Page 3

10 Interconnection Approval Times The length of utility reviews for interconnection applications can be so long that the project timeline is unacceptable for investors. Standard interconnection processes do specify timelines (either strict deadlines or guidelines), and as a result the review times have improved from what stakeholders have seen in the past. However, utilities often exceed the timelines or quote very long lead times. This can be particularly concerning for facilities such as large industrial companies with project timelines that need to be aligned with financial and operational demands. Application and Study Costs Costs to project developers for utilities to conduct interconnection studies vary significantly across utilities, and are often unknown before submitting the applications. For the same set of equipment being installed, the fees can be $1,000 in one area and $15,000 in another. Because of unknown fees and system upgrade costs prior to conducting the interconnection studies, some developers submit applications in the early stages to determine the costs, before they have committed to a project. This results in a large number of applications for the utility to process, burdening utility staff and slowing down processing times for all applicants. Importance of Good Relationships Many project developers expressed the importance of a good working relationship with the utility interconnection team. Good communication with the utility can offer a better understanding of utility needs and what they are more likely to approve; this can help reduce response times. Conclusion Along the same vein, experience with distributed generation interconnection in a particular utility territory can be a great advantage. Project developers gain knowledge from each project, and are best equipped to put forward interconnection applications that contain the information and technical components required by the particular utility. Also, there is value to the project developer and the utility in repeat applications of the same equipment package. Such a cookie cutter approach reportedly takes less time and effort on both sides and is much more likely to result in utility acceptance. This study addresses the current interconnection requirements, standards, and procedures in several key regions of North America, including New York and the Northeast, California, Ontario, and Minnesota. The grid impacts and technical issues associated with behind-the-meter generators were investigated and it was determined how protective relays, inverters, and other equipment can mitigate these impacts. While it is clear that universal standardization of interconnections for all types and sizes of onsite generators among all electric utilities will never be possible or appropriate, there is still room for considerable standardization and harmonization. Current interconnection standards have helped in the last few years, but more progress is achievable. Widespread interconnection of solar PV systems into the grid is providing a large body of knowledge and experience that can help developers with interconnection requirements for CHP systems. In many cases equal treatment of all technologies from a technical and safety point of view has not yet been achieved. Equal treatment on an administrative basis is also lacking. Broader acknowledgement of the environmental and efficiency benefits of CHP by policy makers and state regulators could help this technology achieve more equal treatment in terms of net metering and power exporting. Even if parity with renewable technologies cannot be fully achieved in regards to net metering, neutral policies that simply enable incidental exporting would allow CHP systems to meet more of the customer s electrical load and result in more favorable economics. Inverter-based and synchronous generators offer the ability to operate both in parallel with the grid and in standalone (or islanded) mode. If a CHP generator can serve as a backup generator and support the grid during periods of high demand, it potentially increases the value of the CHP unit and improves the economics of the CHP system. The combined use of natural gas generators for continuous operation, operation during peak periods, and backup during utility outages can simultaneously meet environmental and efficiency policy goals while improving grid reliability and meeting infrastructure resiliency goals. CHP Interconnection Equipment Analysis Page 4

11 Several aspects of distributed generation interconnection appear to be fairly universal across different states/provinces and utilities. In other aspects, interconnection requirements vary considerably from state-to-state, and utility-to-utility. The same utility company operating in multiple states can have very different application processes, fees, and technical requirements in each of its jurisdictions. State regulation is the underlying reason for differences in interconnection requirements. Moreover, within a single state, there are still differences in how the rules are interpreted and applied by different utilities. The main reasons for this are differing operating practices and technical characteristics for each utility s electrical distribution system; however, different interpretations of technical risk and safety also play a role. Next Steps While standard interconnection requirements have played a role in harmonizing the interconnection process and associated technical requirements, utilities still vary in how they interpret and apply the standards. GTI recommends further work be carried out to assemble best practices and case studies from regions with wider adoption of CHP and other distributed generation technology to use as examples of how barriers to acceptance can be overcome. Providing this information to a large audience, including policy makers and regulators, could help influence future interconnection rule changes. CHP Interconnection Equipment Analysis Page 5

12 Introduction This report addresses electrical interconnection standards for onsite generation installed at customer facilities, i.e., behind the meter equipment. Common power generation equipment can include inverters, induction generators, and synchronous generators that operate in parallel with the electric utility. Often protective relays and other devices are installed to prevent electrical faults from affecting the utility and/or neighboring electrical customers. Actual interconnection requirements vary considerably from utility to utility in part because their systems use different equipment and operating practices. In some cases, utility interconnection requirements can lead to the installation of redundant protective devices that unnecessarily drive up costs for Combined Heat and Power (CHP) projects. This report provides comparisons of common interconnection standards, practices and issues in several representative North American electric utility regions. It also summarizes common behind the meter equipment, such as generators and electrical protection devices used to ensure safe operation. The goal was to understand where and when wider standardization and harmonization of interconnection practices is possible. Study Approach The approach for this study was to: Review published interconnect standards, requirements and tariffs Review specifications for generation and protection equipment Identify and interview key stakeholders, including: o o o Technical staff at electric utilities and local distribution companies (LDCs) CHP developers in various service territories Organization of this Report Subject matter experts and equipment vendors The balance of this report includes the following sections: Regional Interconnection Standards and Procedures: Compares the requirements in different utility territories and regions. Conclusions: Summarizes findings and discusses common issues with interconnection requirements across the geographical areas studied. Next Steps: Provides recommendations for future work towards harmonizing and standardizing national interconnection efforts. Appendices: Background and Common Terms: Provides the language to talk about interconnection issues and also attempts to cross-reference and relate the different terms used in different jurisdictions. Common Utility Concerns with Electrical Interconnection: Explains common issues and concerns that utilities have with distributed generators and where standardized requirements make sense. CHP Interconnection Equipment Analysis Page 6

13 Regional Interconnection Standards and Procedures Overview Entities at various levels publish standards for interconnection of distributed generation with the electric grid, including: National utility regulatory bodies State and provincial utility regulatory bodies Regional Transmission Organizations (RTOs) and Independent System Operators (ISOs) Electric power distribution utilities Bodies at the national level govern interstate/interprovincial transmission and sale of electricity, RTOs and ISOs manage the inter- and intra-state/province transmission networks, and state/provincial utility regulatory bodies oversee the local distribution utilities. The Energy Policy Act of 2005 (U.S. Congress 2005) requires electric utilities in the U.S. to provide interconnection service for onsite generating facilities to connect to the local distribution facilities. It specifies that services be based on IEEE Standard 1547 for Interconnecting Distributed Resources with Electric Power Systems. The Energy Policy Act also requires state regulatory authorities and nonregulated utilities to establish agreements and procedures that include practices stipulated in model codes adopted by associations of state regulatory agencies. As a result, 32 states plus the District of Columbia now have interconnection standards for some or all distributed generation interconnections, and another 13 states provide guidelines (Figure 1). Figure 1 U.S. States with Distributed Generation Interconnection Guidelines (yellow) and Standards (green) (DSIRE 2015) CHP Interconnection Equipment Analysis Page 7

14 Canada s equivalent to IEEE 1547 is included in two standards: C22.3 No. 9 Interconnection of Distributed Resources to Electricity Supply Systems for distributed resources in general, and C22.2 No. 257 Interconnecting Inverter-Based Micro-Distributed Resources to Distribution Systems for inverter-based generation and systems where the point of common coupling is at low voltage. Provincial system operators and utilities have published application guidelines, interconnection procedures, and technical interconnection requirements specific to their needs. The technical requirements refer to the above national standards as well as some international requirements, such as IEEE Guidelines typically apply to net-metering interconnections with maximum capacity of kw. The standards, on the other hand, typically have upper limits of MW, though a handful are as low at 1-2 MW, and almost a third do not express a limit on capacity (Table 1). Table 1 Maximum System Capacity Covered by State and Provincial Interconnection Standards Maximum System Capacity State/Province 30 kw KY* 1 MW AB*, NH*, SK 2 MW FL*, NY, WV 5 MW PA* 10 MW CO, DC, IA, MB, MD, MN, ON, OR, SD, TX 15 MW WI 20 MW CT, NV, OH, UT, VA, WA 80 MW NM None specified AB, CA, HI, IL, IN, MA, ME, MI, NC, NJ, RI, VT * Only applies to net metered systems; bolded states are highlighted in this report Source: DSIRE 2015, Manitoba Hydro 2011, OEB 2015, SaskPower 2005, ADGTPC A prospective customer-owned onsite generator must apply for interconnection with the electric utility from which it receives distribution service. It is common for a utility to publish its own interconnection documents. These typically follow state or provincial standardized interconnection documents, but often contain additional details and may even vary slightly from the state or provincial documents. If some of the power generated onsite is to be exported to the grid, the project may also have to comply with RTO/ISO and/or national (e.g., FERC) interconnection requirements. There are four main parts to interconnection standards: Application, review, and approval procedures; Application forms; Interconnection agreements; and Technical requirements. Not all states or utilities have standards for all four of these parts. They may be found in a single document, or the standards might be scattered in multiple utility and public service commission documents and websites. Table 2 summarizes which components are included in six interconnection standards that were reviewed. CHP Interconnection Equipment Analysis Page 8

15 Table 2 Interconnection Standard Components Standard Max. Capacity Application/ Approval Process Application Forms Technical Requirements Interconnection Agreements USA FERC SGIP/SGIA 20 MW California CA Rule 21 None CAISO GIDAP SCE Rule 21 None SCE WDAT None SCE NEM 1 MW PG&E Rule 21 None PG&E WDAT None PG&E NEM 1 MW Minnesota Minnesota PUC 10 MW Xcel Energy 10 MW New York NY SIR 2 MW National Grid SIR 2 MW NYSEG/RGE SIR 2 MW Con Edison SIR 2 MW Canada Canada C MW Ontario Ontario DSC None Hydro One 30 MW Notes: - included, - not included/addressed Federal Energy Regulatory Commission (FERC) FERC s Small Generator Interconnection Agreements (SGIA) and Procedures (SGIP) apply to systems with capacity up to 20 MW interconnecting with entities involved in interstate transmission of electricity such as RTOs and ISOs (FERC 2013, 2014). The SGIA and SGIP may also apply if a generation facility wishes to sell excess power on the wholesale electricity market. Similar agreements and procedures exist for generation facilities that are larger than 20 MW. While the SGIA and SGIP do not normally apply to interconnections of distributed generation with distribution utilities, many state-level standards for such connections have used them as a guideline and have similar processes. FERC has three separate procedures in the SGIP depending on generation technology and installed capacity (Table 3 and Table 4). CHP Interconnection Equipment Analysis Page 9

16 Table 3 Eligibility for FERC SGIP Pathways Procedure Eligibility 10 kw Inverter Process Certified inverter-based facilities 10 kw Fast Track Process Study Process Synchronous and induction machines 2 MW Inverter-based systems as in Table 4 Any other facility 20 MW Table 4 FERC SGIP Fast Track Eligibility for Inverter-Based Systems Line Voltage Eligibility Regardless of Location Eligibility if on Mainline and 2.5 Electrical Circuit Miles from Substation < 5 kv 500 kw 500 kw 5 kv and < 15 kv 2 MW 3 MW 15 kv and < 30 kv 3 MW 4 MW 30 kv and 69 kv 4 MW 5 MW FERC also certifies qualifying small power production and cogeneration facilities. Becoming a Qualifying Facility gives the generation facility the right to sell energy or capacity to a utility, purchase services from utilities, and receive relief from certain regulatory burdens. California Interconnections with distribution utilities in California are under one of two tariffs: Rule 21 under California Public Utilities Commission (CPUC) jurisdiction, or the Wholesale Distribution (Access) Tariff (referred to hereafter as WDAT, but sometimes also called WDT under FERC jurisdiction. Distributed generation connecting to the transmission grid applies for interconnection directly to the California ISO (CAISO) subject to the CAISO Tariff. Each of the large investor-owned utilities (Table 5) publishes its own Rule 21 and WDAT tariffs that follow the CPUC and FERC tariffs, and several smaller investor-owned and municipal utilities also have similar interconnection rules. Figure 2 shows which tariff applies in which situation in California. Table 5 Large Investor-Owned Electric Utilities in California Utility Pacific Gas and Electric Company (PG&E) Territory Most of the northern two-thirds of California CHP Interconnection Equipment Analysis Page 10

17 Utility San Diego Gas & Electric (SDG&E) Southern California Edison (SCE) Territory San Diego County and southern Orange County Much of southern California Figure 2 Distributed Generation Interconnection Chart for California Rule 21 was first adopted in 1982, before FERC developed WDAT. It was developed for the interconnection of Qualifying Facilities (QFs), which are renewable or cogeneration facilities as defined in California s Public Utility Regulatory Policies Act (PURPA) of 1978 (CPUC 2011). CHP Interconnection Equipment Analysis Page 11

18 Generally, three categories of distributed generation operating in parallel with the electrical grid are eligible to apply for interconnection through Rule 21: Non-export: power will never be exported to the grid, Net energy metering (NEM): excess power is exported to the grid in exchange for credits on the customer bill, and Power purchase agreement (PPA): qualifying facilities connected to the distribution grid that have a power purchase agreement with the distribution utility. NEM is available for specified renewable energy sources, fuel cells, and biogas, up to 1 MW per premise. It is not available for CHP unless the system utilizes digester gas, municipal solid waste conversion, landfill gas, or biogas. For distributed generation that is not net metered but will export power to the distribution grid, which interconnection process it will use (Rule 21, WDAT, or CAISO) depends on the requirements of the program it falls under and the nature of the power purchase agreement. Both Rule 21 and WDAT contain: Application and review process, Application forms, Technical requirements, and Interconnection agreements. Utility Interconnection Documents The WDAT tariffs for CAISO, SCE, PG&E, and SDG&E originally had separate interconnection procedures for small ( 20 MW) and large (> 20 MW) generators, the SGIP and LGIP. CAISO merged the two processes into a single Generator Interconnection Process (GIP), approved by FERC in 2010, and both SCE and PG&E have since followed suit. The tariffs for each utility use much of the same language but are not identical. In June 2015, CAISO updated its tariff to replace its GIP with a Generator Interconnection Deliverability Allocation Process (GIDAP) (CAISO 2015). Interconnections under WDAT currently follow the GIP in Attachment I of SCE s WDAT Tariff and PG&E s WDT Tariff, regardless of distributed generator capacity (SCE 2010, PG&E 2014). Similarly, Rule 21 interconnections follow the submission and review processes, design and operating requirements, and testing procedures in each utility s Rule 21 Tariff for Generating Facility Interconnections (SCE 2014, PG&E 2015a). Each utility also provides handbooks and manuals pertinent to distributed generation interconnection. For all SCE interconnections, the technical requirements for design, construction, operation, and maintenance that interconnections must follow are given in SCE s Interconnection Handbook (SCE 2012). The handbook provides separate technical requirements for three categories of interconnection: > 34.5 kv, 34.5 kv and 200 kva, and 34.5 kv and < 200 kva. There is also an interconnection handbook specifically for net energy metering (SCE 2015a). Guidance and instructions pertaining to electrical service connections in general are given in SCE s Electrical Services Requirements manual (SCE 2015b). For PG&E interconnections, the technical requirements are provided in PG&E s Distribution Interconnection Handbook (PG&E 2003). 1 All of the above documents plus additional information are available on utility websites (PG&E 2015b, SCE 2015c). Protective Requirements and Equipment Certification Both SCE and PG&E generally require overvoltage (59), under-voltage (27), under/over frequency (81U/81U), and voltage phase sequence (47) (Table 6). An inverter that is UL 1741-certified has these capabilities and thus may suffice without a protective relay. 1 PG&E s interconnection handbook is currently undergoing revisions, so updates are currently available in a number of separate files. CHP Interconnection Equipment Analysis Page 12

19 Protective Function Table 6 Required Protective Functions for PG&E and SCE Interconnections 40 kw PG&E (any technology) kw > 400 kw SCE (induction/ synchronous) < 200 > 200 kva kva SCE (inverter) Sync Check (25) R Under-voltage (27) R R R R R R* R* Reverse Power (32) R R R Phase voltage imbalance (47) R3 R R3 R3 Phase Overcurrent (50/51) R R Ground-fault-sensing Scheme (51N) R R R Overcurrent with Volt. Restraint (51V) or Control (51C) R R Overvoltage (59) R R R R R R* R* Voltage restrained directional time overcurrent (67V) R Over-frequency (81O) R R R R R R* R* Under-frequency (81U) R R R R R R* R* Direct-Transfer Trip R R R R: Required (bolded functions are most common) R*: Required unless UL 1741-certified R3: Required for three-phase generators < 200 kva > 200 kva Previously, a database of certified equipment for Rule 21 covered numerous technologies. However, now equipment is only being certified under California Energy Commission s Go Solar California program for incentive eligibility purposes. Previously-certified equipment continues to retain its certification, although there is no publically available list of equipment online. Certified equipment benefits from a faster interconnection review process and less stringent technical requirements. PG&E requires redundancy in the protection system, so if any one component fails during a fault condition, the generator will still be isolated from the utility grid (PG&E 2003). Both SCE and PG&E allow smaller projects (up to 1 MVA for SCE and up to 1 MW for PG&E) to use industrial quality or industrial-grade relays, otherwise they require more expensive utility quality or utility-grade relays (SCE 2012, PG&E 2003). Approved industrial- and utility-grade relay models listed in PG&E s interconnection handbook are shown in Table 7 and Table 8. Table 7 Industrial-Grade Relays Approved by PG&E (PG&E 2003) Protective Function Arga Basler Electric Square D Synchronizing (25) PRS 250 Under-voltage (27) BE4-27 PR-201-UV Non-directional Overcurrent (50/51) BE4-51 Over-voltage (59) BE4-59 PR-101-OV Under-/Over-frequency (81O/U) BE4-81-O/U R-101-OUF Over-current (51N,V,C) CHP Interconnection Equipment Analysis Page 13

20 Table 8 Utility-Grade Relays Approved by PG&E (PG&E 2003) Manufacturer Non-directional Overcurrent Relay 50/51 Non-directional Over-current Relay Ground 51N ABB (ASEA) (Westinghouse) RXIDF CO DPU-2000R Micro-shield (MSOC) RXIDF CO DPU-2000R ALSTOM MCGG MCGG Basler Electric BE1-51 BE1-51 Beckwith Electric Brush Electric General Electric Schweitzer Woodward M-0420 M-3410 M-3420 M-3430 M-3520 IFC SR-489 SR-745 L-90, T-60 SR-735 SR-737 SEL-251 SEL-311C SEL-321 SEL-351 SEL-501 SEL-387 SEL-387E SEL-587 M-0420 M-3410 M-3425 M-3520 IFC SR-489 SR-745 L-90, T-60 SR-735 SR-737 SEL-251 SEL-321 SEL-351 SEL-501 A ground bank (or grounding transformer) is commonly required by California utilities for short circuit protection of synchronous and induction generators. 2 This utilizes devices 51V or 67V, 51N or 59G (which device is required depends on customer and utility grid specifications), and grounding capability is through a wye-grounded-delta main power transformer or appropriate grounding transformer (SCE 2012). When export is not allowed, the facility must also have reverse power control (32R), with an import set point of 5% of gross generator output. This may require a separate protective relay with remote telemetry if the PCC or utility entrance is remotely located at the pole away from the building. Interconnection Process Prospective distributed generator owners in California apply for interconnection in parallel with other procedures and permits, including program applications, air quality permitting, and any power purchase agreements. Both WDAT and Rule 21 have a number of processing tracks, including a simplified Fast Track process and some more extensive Study processes (Table 9 and Table 10). 2 Personal communication, Arnold Ramirez, Anaergia (Dec 7, 2015) CHP Interconnection Equipment Analysis Page 14

21 Table 9 WDAT Interconnection Processes in California Process Under 10 kw Inverter Process Fast Track Process Independent Study Process Cluster Study Process Application Inverter-based generation no larger than 10 kw Eligible installations consistent with FERC s SGIP Fast Track Process (by generator type, capacity, and location), and equipment meets specified certifications New interconnections or increased generator capacity, electrically independent from earlier-queued interconnection requests Requests that do not qualify for one of the above processes, or fail certain tests during one of the above processes There is currently one cluster study application period per year Table 10 Rule 21 Interconnection Processes in California Process Fast Track Process Detailed Study Process Independent Study Process Distribution Group Study Process Transmission Cluster Study Process Application Non-exporting, net energy metered, or exporting and up to 3 MW capacity on 12 kv, 16 kv, or 33 kv Not eligible for fast track, or fail to pass fast track evaluation Which study process depends on the result of the electrical independence screening tests: Passes electrical independence test for distribution system Fails electrical independence test for distribution system, and passes electrical independence test for transmission system Fails electrical independence test for distribution system, and fails electrical independence test for transmission system In California, the purpose of the study is to determine what equipment and system upgrades are required in order to interconnect the distributed generation. As such, the generation is not approved or denied. Rather, the study results indicate the cost of system upgrades to enable the distributed generator to be added, and then it is up to the potential distributed generator owner to decide if they wish to proceed with the interconnection and pay for any upgrades, or if they want to withdraw their application. The costs can be significant in some situations: if the project triggers an upgrade (i.e., it pushes a particular electrical variable over substation capacity), then that project alone carries the full responsibility of paying for that upgrade. As a result, many applications are submitted in order to find out what the cost would be, and when they find out it makes the project economically infeasible, they withdraw their application. This puts extra burden on the utility staff, particularly when they receive unexpectedly large numbers of applications at one time. As a result, the utilities CHP Interconnection Equipment Analysis Page 15

22 are not always able to meet their specified timelines, though they do maintain communications with the study applicant. 3 Project developers feel the time the utilities take to conduct their reviews is the developer s biggest hurdle to interconnection. Where the target time communicated by the utility is six months, in reality six months is a minimum, and in some cases it takes over a year. Yet, while the utility is able to extend the time they need to complete a study, when the utility needs extra information about the proposed generation facility, they require a response in an extremely short time frame (i.e., days) otherwise the application is discarded. 4 Web-Based Application Portals Utilities in California are rolling out online applications for interconnection. SCE currently has it available for Rule 21 non-export and net energy metering, and the applicant is also able to check the progress of the application online. Similarly, PG&E now has online applications for Rule 21 non-export and certain net energy metered generating facilities, and has also rolled out the capability for Rule 21 export projects. Interconnection Inventories and Queues As required by FERC and CPUC rules, the large investor-owned utilities maintain lists, or queues, that show the current status of applications for interconnection to their distribution system under both WDAT and Rule 21 (not including net energy metering) (SCE 2015d, PG&E 2015c). The lists are publically available, and include dates, status, generation technology, capacity or maximum export power requested, and substation. They include all interconnection applications to date, including those that have completed the interconnection process or have withdrawn their application. System Maps CPUC requires each large investor-owned utility to provide up-to-date maps of the capacity to integrate distributed generation. SCE s interactive map, the Distributed Energy Resource Interconnection Map (DERiM), shows integration capacity by circuit segment, which circuit segments are potentially constrained, and the location of distribution and subtransmission substations (SCE 2015e). For each substation, the map provides the existing distributed generation capacity, queued interconnection applications, projected load, current penetration level (as a percentage of existing plus queued generation capacity out of the total projected load), and the maximum achievable generation capacity. Also available for each circuit segment and substation is whether or not interconnection studies in the area have identified inadequate deliverability. PG&E s map is located on its Solar PV and Renewable Auction Mechanism (RAM) Program website (PG&E 2015d). This map shows the relative capacity for each feeder line section (high to low), capacities (minimal and possible impacts) for each zone by distributed generation technology, and feeder and substation bank capacity limits by distributed generation technology. It is not possible to export power to the grid in PG&E s secondary networks in downtown areas of San Francisco and Oakland, but a non-export option may be available. Minnesota The Minnesota Public Utilities Commission (MPUC) regulates electric utilities in the state of Minnesota. In 2004, it established a standard interconnection process, application, agreement, and standard technical requirements for interconnection of distributed generation (MPUC 2004). The standards apply to any distributed generation technology up to 10 MW. 3 Personal communication, Nina Lamb and Donna McCort, SCE (Dec 2015) 4 Personal communication, Ken Rosentreter, OHR Energy (Dec 2, 2015) and Arnold Ramirez, Anaergia (Dec 7, 2015) CHP Interconnection Equipment Analysis Page 16

23 The standards differentiate a number of interconnection categories, based on the type of transfer between utility and generator load and power offtake (Table 11). The list of documents that pertain to the interconnection increases with the length of time that the generator will operate in parallel with the utility. Table 11 Interconnection Categories in Minnesota (MPUC 2004) Category Open Transfer Quick Closed Transfer Soft Loading Transfer Extended Parallel Description Break-before-make: the local loads are disconnected from the utility grid before being connected to the generator. Open transfer is sub-classified into open transition, and quick open transition which is much faster (< 500 ms). The generator never operates in parallel with the utility grid. Make-before-break: the generator is synchronized with the utility grid and parallels for a short period of time (<= 100 ms) before disconnecting the generator and load from the utility grid. This method is less disruptive than open transfer because the load remains energized throughout the transfer. Make-before-break: the generator is synchronized with the utility grid and parallels for a limited amount of time (under one or two minutes) before disconnecting the generator and load from the utility grid. This method minimizes voltage and frequency disturbances. The generator remains connected with the utility grid for an extended period of time. There are three types of extended parallel systems: QF up to 40 kw, nonexport (without sales), and exporting & net (with sales). Different requirements are given to inverters. Utility Interconnection Documents Investor-owned utilities in Minnesota (Table 12) publish the state standards within their tariffs. Xcel Energy (Northern States Power Company) serves most of the southern half of Minnesota, including the Twin Cities (Minneapolis and Saint Paul) metropolitan area, which is the most populous area in the state. It is thus often held to a higher standard by the MPUC. 5 Table 12 Investor-Owned Electric Utilities in Minnesota Utility Previously Territory Allette Minnesota Power Most of northeastern Minnesota Northwestern Wisconsin Electric N/A Pine County Otter Tail Power N/A Western Minnesota 5 For example, it has higher renewable energy targets as a percentage of its load than the other utilities, and standby charges are exempt for distributed generation up to 100 kw connected to Xcel s grid, but only up to 60 kw at other utilities. CHP Interconnection Equipment Analysis Page 17

24 Utility Previously Territory Xcel Energy Northern States Power Most of the southern half of Minnesota, including Minneapolis and Saint Paul metropolitan area Source: and utility websites. Note: Alliant Energy (Interstate Power & Light) was previously an IOU serving southernmost Minnesota, but as of July 31, 2015, customers are now served by Southern Minnesota Energy Cooperative members. Xcel Energy (Northern States Power Company) lists documents related to distributed generation in its Minnesota service territory on its website. (Xcel 2015). The relevant rules and regulations are spread throughout a number of Xcel Energy s tariffs. Tariff Section 10 contains most of the rules and regulations pertaining to distributed resources, including the interconnection process, application, agreement, and requirements. Section 9 contains rates, rules, regulations, and standard contracts for smaller generation (up to 100 kw) and Qualifying Facilities under PURPA. The standby service rider is in Section 5, and Section 6 contains general rules for parallel operations. While Xcel Energy s Distributed Generation Standard Interconnection and Power Purchase Tariff (MPUC No. 2, Section 10) applies to generators up to 10 MW, the Tariff states that generators at single-phase facilities are generally limited to 25 kw. Protective Requirements and Equipment Certification The MPUC standard technical requirements list the protective requirements that are required by interconnection type, and has separate protection requirements for inverters by size (Table 13). Generally, all parallel generation requires standard protection against islanding (27/59 and 80 O/U) and overcurrent (50/51) faults, as well as a lockout function. A synchronizing check is also required for all but inverters. The requirements state that relays have to meet all applicable ANSI/IEEE standards, including C37.90, C , and C Overall, the system must meet the latest version of all ANSI/IEEE standards, especially IEEE Table 13 Protective Requirements by Interconnection Type in Minnesota (MPUC 2004) Protective Function Open Transition Quick Open Transition Closed Transition Soft Loading, Limited Parallel Soft Loading, Extended Parallel, < 250 kw Soft Loading, Extended Parallel, > 250 kw < 40 kw Inverter kw > 250 kw Overcurrent (50/51) R R R R R R Voltage (27/59) R R R R R R Frequency (81 O/U) R R R R R R Reverse Power (32) R Lockout (86) R R R R R R R R Parallel Limit Timer R R R Sync-Check (25) R R R R R CHP Interconnection Equipment Analysis Page 18

25 Transfer Trip R R The state s standard technical requirements handle certification of whole generation packages, including all switchgear, inverters, or other interface devices and may include an integrated generator or electric source. A system is pre-certified if it is listed by a recognized testing and certification laboratory, for its intended purpose. This generally means that it has passed the type of tests in UL 1741 and IEEE 929. Equipment certification has three advantages: 1. It is acceptable for interconnection without additional protection system requirements. 2. If it has no design modifications, the need for a professional electrical engineer to review and approve the system is waived. 3. The interconnection application fee is lower. Interconnection Process The interconnection process in Minnesota is the same for all interconnections except for net energy billing (< 100 kw) customers. The process contains 11 steps, and includes a preliminary review, engineering study, construction estimates, final design review, construction, testing, and final approval for operation. It also includes points along the way for the applicant to decide whether or not they wish to proceed to the next step based on new information from the review, including the cost of the next stage. Net energy billing customers have a simplified process containing only one review stage, and no engineering study. The standard interconnection requirements set the price for the application and engineering study fees on a sliding scale. The cost increases as systems get larger, and it is more for parallel interconnections than for standalone generators. For the largest systems, there is room in the standard process for the utility to add engineering study fees depending on the complexity of the study required. Web-Based Application Portals Xcel Energy does not have a web-based application portal; all interconnection applications are to be submitted via mail or . Interconnection Inventories and Queues Xcel Energy does not have a public queue for all interconnection requests. However, it has made its solar gardens (community net metering for solar PV) queue public. 6 System Maps Xcel Energy does not have maps showing system capacity for distributed generation publically available on their website. The standard interconnection requirements do not cover connections to a network, and rather than looking at a map, the customer must contact the utility to confirm the utility system type and obtain any additional requirements if it is located on a network or other unique electric power system. New York The New York Public Service Commission (PSC), under the Department of Public Service, regulates electric utilities in New York State. It was the second state to adopt an interconnection standard when it first published the New York State Standardized Interconnection Requirements (SIR) in 1999 for systems up to 300 kw in capacity. 6 Available at SRC-Public-Queue-1.xlsx CHP Interconnection Equipment Analysis Page 19

26 The requirements have undergone several iterations in the past 15 years, and continue to evolve alongside New York s Reforming the Energy Vision (REV) initiative. The current version of the SIR (NY PSC 2015b) applies to distributed generation facilities with an aggregated nameplate rating on the customer side of the point of common coupling (PCC) of 2 MW or less that interconnect in parallel with investor-owned utility distribution systems. Some utilities extend their use of the SIR to larger systems Con Edison, for example, follows the SIR for generation facilities up to 5 MW in capacity and the 2015 Reforming the Energy Vision (REV) order (NY PSC 2015a) directs the initiation of a process to extend the SIR threshold to 5 MW, and this is reflected in the November 2015 proposed update to the SIR (NY PSC 2015c). Larger facilities are more likely to be connected to the transmission system, and thus follow NYISO interconnection requirements. This process falls under FERC jurisdiction and is typically lengthier than the NY SIR process. The SIR contains: application and review process, application forms, and technical requirements. Each utility is also required by REV to have standardized interconnection agreements. Utility Interconnection Documents Each investor-owned utility in New York (Table 14) publishes their own interconnection requirements that supplement the SIR. The requirements also provide guidance for interconnections of facilities larger than 2 MW to their distribution systems. Table 14 Investor-Owned Electric Utilities in New York State Utility Acronym/Abbreviation Territory Consolidated Edison Con Edison NYC/Westchester County Orange and Rockland Utilities ORU Near NY/NJ/PA borders Central Hudson Gas and Electric CenHud Hudson Valley Rochester Gas & Electric 1 RG&E Rochester and south National Grid (Niagara Mohawk) NGrid Albany, Syracuse, Buffalo, Adirondacks New York State Electric & Gas 1 NYSEG Southern Tier PSEG Long Island Power Authority 2 LIPA/PSEG LI Long Island 1 NYSEG and RG&E are subsidiaries of, and operate as, National Grid. 2 Not investor-owned, but tends to follow SIR National Grid (Niagara Mohawk) publishes its interconnection requirements in its Electric System Bulletin No. 756 (National Grid 2014). Appendix B in ESB 756 applies to distributed generation connected to National Grid distribution facilities per the NYS SIR, while Appendix A applies to other parallel generation connected to National Grid facilities in New York. The Bulletin covers the application and interconnection process, general design and operating requirements. As subsidiaries of Iberdrola, NYSEG and RG&E have a single combined interconnection requirements document, Bulletin (NYSEG/RGE 2011). This document covers interconnections of facilities as covered in the NYS SIR, as well as those that are greater than 2 MW and up to 20 MW that are not covered by the NYISO SGIP (i.e., CHP Interconnection Equipment Analysis Page 20

27 they are connecting to the distribution rather than transmission system). It covers the utility s application and review process as well as technical requirements. Con Edison publishes its requirements for dispersed generation customers in Specification EO-2115 (ConEd 2006). This covers net metered generation sources, NYS SIR generation, and dispersed generation larger than 2 MW and up to 20 MW. It includes the application process, technical requirements, and standard forms. Con Edison uses the SIR timeline and application process for all facilities up to 5 MW. Protective Requirements and Equipment Certification The minimum protective function requirements specified in the SIR are given in Table 15. Utilities may require additional protection, but must evaluate this on a case-by-case basis and provide justification. Table 15 Minimum Protective Requirements in NY SIR Protective Function Synchronous Generators Induction Generators Inverters Over/Unver Voltage (27/59) Currently required Currently required Currently required Over/Under Frequency (81O/81U) Currently required Currently required Currently required Anti-Islanding Protection Proposed (Nov 2015) Proposed (Nov 2015) Currently required Overcurrent (50P/50G/51P/51G) Proposed (Nov 2015) Proposed (Nov 2015) Proposed (Nov 2015) Source: NY PSC 2015c. The New York Standard Interconnection Requirements (NY PSC 2015b) defines utility-grade relays as those that meet the specifications in Table 16. Table 16 Utility-grade Relay Specifications in the New York Standard Interconnection Requirements Standard Conditions Covered ANSI/IEEE C37.90 ANSI/IEEE C IEEE C ANSI C37.2 IEC IEC IEC Usual Service Condition Ratings Current and Voltage Maximum design for all relays AC and DC auxiliary relays Make and carry ratings for tripping contacts Tripping contacts duty cycle Dielectric tests by manufacturer Dielectric tests by user Surge Withstand Capability (SWC) Fast Transient Test Radio Frequency Interference Electric Power System Device Function Numbers Vibration Electrostatic Discharge Insulation (Impulse Voltage Withstand) Certified equipment may not require any additional protective devices. The SIR states that equipment is certified if the equipment is tested and certified to be compliant with UL 1741 by a Nationally Recognized Testing Laboratory. If it is tested and certified by a non-nrtl, the compliance documentation must be reviewed and CHP Interconnection Equipment Analysis Page 21

28 approved by the NY PSC before being added to their certified interconnection equipment list (NY PSC 2015d). 7 The NY PSC will also add NRTL-certified equipment to the list. Up until a few years ago, the PSC added a number of types of technologies to their list, including inverters, protective relays, microturbines, and CHP units. Now, the PSC is primarily concerned with anti-islanding capabilities and thus only reviews and approves inverter technologies, leaving other technologies to the utilities that have more expertise in their specific needs. In many cases in New York, the internal generator controls do offer protection but are not certified. LIPA had been known in the past to accept on-board controls for small induction generator units without additional protect relays, but Con Edison typically does not. 8 More often a protective relay from the certified equipment list is used. 9 And in some cases, even if the equipment is fully certified, the utility still requires an additional, redundant, protective relay. 10 Table 17 lists all non-inverter interconnection equipment that the PSC has approved and added to their certified equipment list. Hundreds of inverters have also been certified, some which have been designed specifically to be used in conjunction with a rotating generator. 11 Table 17 Non-Inverter Interconnection Equipment Certified by NY PSC (NY PSC 2015d) Device Type Manufacturer Model No(s) CHP Unit Honda MCHP 1.2 MCHP 1.2D MCHP 1.2DP Marathon Engine Systems Tecogen Ecopower CM-60 CM-75 Microturbine Capstone Turbine 65 C60 Microturbine (330) 30 MicroTurbine 60, C60, 60 SA, C60 SA, C60 ICHP Protection Relay Elliott Energy Systems PE100-4B-8 Beckwith Electric M-3410 M-3410A M-3520 Schweitzer Engineering Labs SEL-351A00H24552XX For non-export installations the utilities are most concerned with limiting the fault current contributions. This is not a problem for inverters, which are able to respond within half a cycle. Induction units stop contributing fault current after cycles. Synchronous generators are often sites on radial distribution systems but are difficult to 7 The list has been split into two files for convenience. Equipment on the pre-2011 list is still considered certified, irrespective of technology type. 8 Personal communication, Gregg Giampaolo, All-Systems Cogen (Dec. 7, 2015) 9 Personal communication, Dave Thompson, Aegis (Dec. 8, 2015) and Sal Cona, Intelligen (Dec. 4, 2015) 10 Personal communication, Tecogen (Dec. 9, 2015), Gregg Giampaolo, All-Systems Cogen (Dec 7, 2015) 11 Included on the list are Tecogen s PCS II inverter (used with its INV-100e+ CHP Module) and TS inverter (used with its INV-100 CHP Module). CHP Interconnection Equipment Analysis Page 22

29 install in the network areas in Con Edison territory. In spite of the fact that detailed fault current maps show where synchronous generators can be applied, it is reportedly still cost prohibitive to do so. 12 Reverse power protection (32) is also widely required in New York. The purpose is to ensure the unit goes down immediately after a utility outage. The protective relay must have CTs installed at the facility meter (at the PCC) and settings often require that the generator is tripped off after two seconds of any reverse power flow. At least one vendor 13 thinks this requirement is too onerous for small CHP units. A more relaxed reverse power approach of using pulse signals from a power transducer on the facility mains could result in reverse power protection with a response time on the order of 15 seconds. This would allow the generator output to run closer to the facility load without a large import requirement. Most CHP systems designed for both parallel and off-grid (backup) operation in New York have been installed with manual disconnect switches that require someone to physically disconnect the utility before connecting the generator to the load for standalone operation. These two disconnects often use kirk-keys so that both disconnect switches cannot be closed at the same time. 14 Con Edison is now indicating that they are open to motorized breakers that would allow the changeover to happen automatically in future installations. 15 This change will allow facilities to have a more automated transition during grid outage (though it still will not be seamless). Within secondary networks in New York City and downtown areas in other parts of the state, it is nearly impossible to get approval to interconnect a synchronous generator. Even in zones on the system map that have been identified as having available fault current it can be extremely difficult to gain approval or implement a project cost effectively. Induction generators are accepted, but often not preferred by the customer because they do not provide black start capability. Inverter technology, on the other hand is the preferred technology in Con Edison territory because of its ability to provide backup power (deemed important in the wake of Hurricane Sandy) while not adding to potential fault current. The NYSERDA CHP Acceleration program provides financial incentives that help offset the added cost of having an inverter. 16 Any disputes on the results of the interconnection study, for example, system upgrades or additional protections that are found to be required, are taken to the PSC. This is rare with certified equipment, and is more common with larger systems and non-inverter technology. Common disputes are over requirements for system upgrades including direct transfer trips, re-closers, and 3vo grounding. 17 Interconnection Process According to the current applicable version of the SIR, all systems of 50 kw or less are eligible for an expedited application process. The SIR also encourages utilities to use the expedited process for inverter-based systems up to 300 kw. In practice, some of the utilities only apply the expedited process to systems up to 25 kw (the upper limit for residential net metering for solar PV), while systems up to about kw that do not qualify for the expedited process use a screening analysis (previously a preliminary review ). A full Coordinated Electric System Interconnection Review (CESIR) is required if the prospective generation facility does not pass the expedited process or screening analysis, and it is also always required in some specified cases (Figure 3). While the contents of the screening analysis have not previously been specified by the standard, Appendix G of the redlined SIR proposes six simple screens. 12 Personal communication, Sal Cona, Intelligen (Dec. 4, 2015) 13 Personal communication, Tecogen (Dec. 9, 2015) 14 Personal communication, Sal Cona, Intelligen (Dec. 4, 2015) and Gregg Giampaolo (Dec. 7, 2015) 15 Personal communication, Sal Cona, Intelligen (Dec. 4, 2015) 16 Personal communication, Sal Cona, Intelligen (Dec. 4, 2015), Tecogen (Dec. 9, 2015) 17 Personal communication, Jason Pause, NY DPS (Dec. 1, 2015) CHP Interconnection Equipment Analysis Page 23

30 Figure 3 Maximum Capacity for Interconnection Application Processes in New York, as Reported by the Electric Utilities (NYSERDA 2015) The interconnection process in general has three stages: (1) application and study, (2) installation, and (3) testing. While project developers have control of the installation stage, they commonly feel that the time it takes for the application and study and testing stages is a hindrance. 18 Project developers are particularly impatient for the testing stage, since fully completed projects often sit unused for 1-2 months awaiting the utilities to schedule a time for witness testing as the only remaining requirement for the project to start producing power. 19 That being said, as a result of the SIR and the timelines that it mandates (and potentially also because interconnection of PV and CHP has become common and is no longer considered a special case), the time for the interconnection process has become shorter. 20 Web-Based Application Portals Phase I of REV orders utilities to have a web-based interconnection application portal in operation by December 15, 2015, and the November 2015 red-lined SIR proposes it be available for all systems up to 25 kw. The REV order states that portals will allow submission of interconnection applications through their websites. CenHud, Con Edison, and ORU already have online application portals that also provide details on the application status. The REV order also mandates that portals include management tools and automatic screening based on impacts of distributed generation on the grid (e.g., load flow and fault potential from distributed generation penetration levels). While the currently proposed redline version of the SIR does not specify automatic screening, it does require as a minimum for the portal to contain basic project details, application status, outstanding actions and deadlines, and payment information. Capabilities are to be expanded in Phase II of REV to integrate the web portal with grid optimization planning, and will include the potential impacts that distributed generation will have on the system, such as load flow and protection at the feeder level. 18 Personal communication, Gregg Giampaolo, All-Systems Cogen (Dec. 7, 2015) and Dave Thompson, Aegis (Dec. 8, 2015) 19 Personal communication, Dave Thompson, Aegis (Dec. 8, 2015) 20 Personal communication, Sal Cona, Intelligen (Dec. 4, 2015) and Dave Thompson, Aegis (Dec. 8, 2015) CHP Interconnection Equipment Analysis Page 24

31 Interconnection Inventories and Queues Each utility is required to submit an inventory of SIR projects to the PSC monthly (before September 2015, they only had to submit the inventories quarterly). The inventory must include basic information on their distributed generation interconnections, including the current application queue, system type, capacity, whether or not it is net metered, protective equipment, dates of each stage of the interconnection process, and various associated costs. The utilities vary in their interpretation of what is required in some of the fields. For example, CenHud, National Grid, and Iberdrola provide the model of the inverter or protective relay under the protective equipment field, whereas Con Edison and ORU simply state whether the protection is an inverter, induction generator, synchronous generator, or relay. New York s interconnection inventories are less comprehensive than in California. Some utilities simply send information on the current queue, and not all SIR interconnections to date. Interconnection inventories submitted to the PSC are available on their document management system (NY PSC 2015e), but only in their submitted form. System Maps National Grid provides maps showing the location of secondary networks in its distribution system (National Grid 2015). Con Edison provides maps showing potential areas for synchronous generation without fault current mitigation, and where fault current mitigation is required with the year that Con Edison plans to complete the upgrade (Con Edison 2015). Ontario Ontario s Distribution System Code contains the standardized connection process and technical requirements for interconnection of distributed generation commonly referred to in Ontario as embedded generation when located behind the customer meter to the distribution system ( 50 kv) (OEB 2015b). The Code contains: application and review process, and technical requirements, and it references a mix of Canada (CAN/CSA), Ontario (OESC) and IEEE standards. The Distribution System Code does not have an upper limit on capacity that it applies to, but it does give separate connection processes for four generator categories based on nameplate rated capacity and connected distribution system voltage: micro ( 10 kw), small ( 500 kw on < 15 kv, or 1 MW on 15 kv), mid-sized (> 500 kw on < 15 kv, or > 1 MW and < 10 MW on > 15 kv), and large (> 10 MW). Utility Interconnection Documents Ontario s Distribution System Code applies to all electricity distributers licensed by the Ontario Energy Board under Part V of the Ontario Energy Board Act, Ontario currently has over 80 licensed electricity distributers, which are referred to as local distribution companies, or LDCs (OEB 2015a). The largest LDC is Hydro One, which is also a transmission utility. Interconnection applications are made to the LDC that holds the service territory the facility is located in. Many of the smaller LDCs complete the Connection Impact Assessment (CIA) themselves, but Hydro One, as the owner of the transmission lines, also conducts its own CIA. Hydro One publishes two Technical Interconnection Requirements documents for distributed generation (to distribution system feeders): micro generation installations ( 10 kw) and three-phase small generation installations < 30 kw (Hydro One 2010), and CHP Interconnection Equipment Analysis Page 25

32 all other BTM generation installations (Hydro One 2013). Protective Requirements and Equipment Certification The Distribution System Code lays out some basic technical requirements for distributed generation in Ontario (in Appendix F.2). Each local distribution company publishes Technical Interconnection Requirements (TIRs) that are consistent with the Distribution System Code, but also add further information and requirements. Hydro One requires that protection relays be utility grade (not industrial grade ), meet minimum requirements specified in IEEE C37.90, and also meet specified electromagnetic interference and surge withstand requirements. Table 18 shows the minimum protective functions that are required for connections of distributed generation with Hydro One s distribution grid. Table 18 Minimum Protective Functions Required for Distributed Generation Connected to Hydro One Distribution System Function Requirement Protective Function Single- Phase Facilities Synchronous Generators Three-Phase Facilities Induction Generators Inverters Interconnect Disconnect Device (89) R Generator Disconnect Device R Basic Anti- Islanding Tele- Protections Other Passive Anti-Islanding Phase Fault Protection Over/Unver Voltage (27/59) R R R R Over/Under Frequency (81O/81U) R R R R Transfer trip receive (TTR) M M M Distributed Generator End Open/Low Set Block Signal (DGEO/LSBS) M M M Rate of change of Frequency (81R) M a M a Vector surge (78) or Directional Reactive Power Relay (32R) Overcurrent (50/51) Phase Fault Overcurrent (50) R R R R M a M a Phase Inverse Timed Over-current (51) A/C (50) A/C (50) A/C (50) Voltage Controlled Over-Current (51V) A/C (50) A/C (50) A/C (50) Directional Phase Overcurrent (67) R R R (Phase) Distance (21) R M M M Under-voltage (27) M M M Neutral Over-current (50N) R R R CHP Interconnection Equipment Analysis Page 26

33 Function Requirement Protective Function Single- Phase Facilities Synchronous Generators Three-Phase Facilities Induction Generators Inverters Ground Fault Protection Neutral Inverse Timed Over-current (51N) M M M Directional Neutral Over-current (67N) R R R Ground Distance (21N) M M M Under-voltage (27) M M M Ground Overvoltage (59G) M M M Open Phase and Phase Unbalance Negative Sequence Current (46) M M M Negative Sequence Voltage (47) M M M Ferro-resonance Peak Detecting Overvoltage (59I) M M Synchronization Synchronizing (25) M b M M M R: Required M a : Permitted instead of transfer trip for 500 kw A/C (50): Alternate or compliment to Phase Fault Overcurrent (50) M b : Only for synchronous generators and other types with standalone capability The utilities commonly accept Beckwith, SEL, and GE protective relays for utility protection, and which generator protection is used is up to the vendor. 21 Inverters must meet CSA standards C and CAN/CSA 22.2 No , and also carry a certification recognized in the Ontario Electrical Safety Code. Systems larger than 1 MW generally require a transfer trip. The transfer trip system senses the loss of utility power and sends a signal to either the generator breaker or utility breaker, depending on the project, to separate the generator from the utility grid (Hydro One 2013). Adding a transfer trip can add significant cost to the project, particularly if it is on multiple feeders. 22 For systems under 1 MW, the generator capacity is usually a small portion of the load so a transfer trip is not needed. Depending on the grounding potential rise found in the grounding study as part as the CIA, a grounding grid may be required. This is a passive system that adds multiple parallel routes from the generator to ground. 23 Because Ontario s electrical grid is mostly radial, it is primarily limited by thermal capacity, i.e., the amount of MW of distributed generation that can be installed on any one substation/feeder. There exist areas where thermal loads are enough for cogeneration to be viable (e.g. the manufacturing sector) but the substations are not able to support additional thermal capacity. Greater transparency on timelines for substation upgrades would be useful in this situation, to allow for facilities to plan for future possibilities Personal communication, Matt Lensink (Dec. 15, 2015) 22 Personal communication, Matt Lensink (Dec. 15, 2015) 23 Personal communication, Matt Lensink (Dec. 15, 2015) 24 Personal communication, Matt Lensink (Dec. 15, 2015) CHP Interconnection Equipment Analysis Page 27

34 Some areas are also limited by fault current, and investigations are being made into technologies that may allow distributed generation to be installed in areas with limited fault current. One such technology that may be useful for non-export generators is the CLiP (Current Limiting Protector), which quickly interrupts the fault using an electronic trigger linked to an explosive. While promising and already in limited use, this device still has some hurdles to overcome in Ontario before it gains widespread utility acceptance. Some of the hurdles yet to be overcome are capital cost, cross-border transport (it is manufactured in the U.S.), and nuisance trips (it is a singleuse device). 25 Interconnection Process Ontario s Distribution System Code lays out the interconnection process for all distributed generation in the province (in Section 6.2). Micro-embedded generation facilities (< 10 kw) have a simplified application process and forms. All other sizes start the process with a Pre-FIT Consultation Application online form. All but micro-embedded generation facilities must undergo a CIA from the distribution utility, and large embedded generators must then also undergo a System Impact Assessment by the Ontario Independent Electricity System Operator (IESO). 26 Other activities are required alongside the interconnection application, some which must occur before the next stage of the interconnection process can begin. The generation facility will need to sign a contract with IESO if participating in a standard offer program such as CHPSOP 2.0, 27 or a feed-in-tariff program. 28 There may be additional requirements if taking part in the net metering program. 29 A Generator License is required if the generator will sell excess energy into the IESO-administered market or through the distributor (along with a connection agreement and service agreement with the distributor). The License is not required where the output of the generation facility is intended exclusively for the customer s own consumption ( load displacement ) or for net metering customers. The Ontario Ministry of the Environment may need to conduct an environmental assessment, depending on the size, type, fuel, and location (it is generally not needed for generation facilities less than one MW). After the generation facility is constructed, the Electrical Safety Authority must inspect it and provide authorization for it to be connected to the distribution system. Generally, the CIA is carried out by the LDC in a reasonable amount of time (2-3 months), but the CIA carried out by Hydro One can take longer. This delay is particularly an issue for large industrial customers, who expect the process to occur in a timely manner. 30 Web-Based Application Portals Generators over 10 kw that wish to interconnect with Hydro One s distribution grid begin the application process with an online Pre-FIT consultation. 25 Personal communication, Matt Lensink (Dec 15, 2015), Tim Short (Nov. 30, 2015) 26 The Ontario Power Authority (OPA) merged into the Independent Electricity System Operator (IESO) on Jan 2., 2015 (Source: 27 The Combined Heat and Power Standard Offer Program 2.0 (CHPSOP 2.0) is opened when directed by the Ontario Energy Minister. Through the CHPSOP 2.0, the OPA procures contracts for CHP projects up to 20 MW specifically for agricultural industry or district energy projects. On June 26, 2015, contracts were executed with 57.6 MW of agricultural industry projects and 34.4 MW of district energy projects for the first application window. It is not clear when the next application window will be. More information is available at 28 The IESO has feed-in tariff (FIT) programs (FIT Program for > 10 kw and microfit for 10 kw and generally 500 kw), which are for connections under a fixed-price contract. The FIT programs only apply to generation from specific renewable energy sources. More information is available at 29 Hydro One offers a net metering program to renewable energy generation 500 kw primarily for onsite use, allowing generators to export excess electricity to the grid in return for credits toward electricity costs. More information is available at 30 Personal communication, Matt Lensink (Dec. 15, 2015) CHP Interconnection Equipment Analysis Page 28

35 Interconnection Inventories and Queues Hydro One is required by Ontario s Electricity Act to maintain a list of current applications for renewable generation facilities to interconnect with its distribution system (Hydro One 2015a). The list only contains projects that make a successful application to connect with Hydro One s distribution system, including all systems eligible for a CIA and generators installed before the RESOP program. It includes the application date, station, feeder, and nameplate capacity, but does not list the generation technology type. System Maps Under the Distribution System Code, distribution utilities must provide a map of the area upon request at no cost to the customer, showing distribution and sub-transmission lines, transformer and distribution stations, and the voltage levels used for distribution. The utilities must also provide the voltage and fault levels, minimum and maximum feeder loadings, and the amount of additional generation that can be accommodated. Hydro One has an application form for generation greater than 10 kw on their website (Hydro One 2015b). Hydro One has a downloadable spreadsheet, the Station & Feeder Capacity Calculator, to determine whether or not the proposed distributed generator is within station or feeder capacity (Hydro One 2015c). If the proposed project passes the tests, it gives instructions for how to apply for interconnection. The calculator currently only has options for biomass/biogas, hydraulic, solar, and wind, but can give a general indication if capacity may be available or not for other technologies. Hydro One also maintains a list of thermal (MW) and short circuit (MVA) capacities for distributed generation by substation bus and feeder (Hydro One 2015d). CHP Interconnection Equipment Analysis Page 29

36 Conclusions This study reviewed the current interconnection requirements, standards, and procedures in several key regions of North America, including New York and the Northeast, California, Ontario, and Minnesota. The grid impacts and technical issues associated with behind-the-meter generators were investigated and it was determined how protective relays, inverters and other equipment can mitigate these impacts. A number of aspects of the interconnection of distributed generation were found to be fairly universal across multiple states/provinces and utilities. In other aspects, interconnection requirements vary considerably from state to state, and utility to utility. The same utility company operating in multiple states can have very different application processes, fees, and technical requirements in each of its jurisdictions. State regulation is the underlying reason for these differences. However, within a single state there are still variations in how the rules are interpreted and applied by separate utilities. The main reasons for this are diverging operating practices and technical characteristics for each utility s electrical distribution system; however, different interpretations and understanding of technical risk and safety also play a role. While it is clear that universal standardization of interconnections for all types and sizes of onsite generators among all electric utilities will never be possible or appropriate, there is still room for considerable standardization and harmonization. Current interconnection standards have helped considerably in the last few years, but more progress is achievable. Widespread interconnection of solar PV systems into the grid is providing a large body of knowledge and experience that can inform interconnection requirements for CHP systems. In many cases equal treatment of all technologies from a technical and safety point of view has not yet been achieved. Equal treatment on an administrative basis is also lacking. Broader acknowledgement of the environmental and efficiency benefits of CHP by policy makers and state regulators could help this technology achieve more equal treatment in terms of net metering and power exporting. Even if parity with renewable technologies cannot be fully achieved (i.e., net metering), more neutral policies that simply enable incidental exporting would allow CHP systems to meet more of the customer s electrical load with more favorable economics. Next Steps As discussed in this report, barriers and hurdles still exist when installing and interconnecting behind-the-meter CHP generators and protective equipment. Further work is recommended to assemble best practices and case study examples from various regions with wide adoption of CHP (and solar) to use as an example of how these difficulties can be overcome. Examples of several key issues to highlight include: the need for reverse power protection and potential for relaxed requirements (in light of widespread net metering for solar), a clearer understanding of when outdoor-mounted disconnect switches are required and electrical room mounting is acceptable, and streamlined application and approval processes for small CHP harmonized with solar application processes. Inverter-based and synchronous generators offer the ability to operate both in parallel with the grid and in standalone (or islanded) mode. If a CHP generator can also serve the function of a backup generator, this potentially increases the value of the CHP unit and improves the economics of the CHP system. Backup generators that use cleaner fuels such as natural gas can also periodically operate to support the electric grid during periods of high demand. Future work to understand the use of natural gas as a fuel for backup generators would be a valuable next step. Numerous codes require that backup (or emergency) generators have onsite fuel storage in many building applications. Case studies and natural gas reliability data are needed to help argue that natural gas is a reliable fuel and prove the value that CHP can add at sites and to the system as a whole. The combined use of natural gas generators for continuous operation, operation during peak periods, and backup during utility outages can simultaneously meet environmental and efficiency policy goals while also improving grid reliability and meeting infrastructure resiliency goals. CHP Interconnection Equipment Analysis Page 30

37 CHP Interconnection Equipment Analysis Page 31

38 References ADGTPC Alberta Distributed Generation Interconnection Guide. Alberta Distributed Generation Technical and Policy Committee. Jul. 16, Available at 16.pdf. CAISO ISO Tariff, Appendix DD Generator Interconnection and Deliverability Allocation Process as of Jun 12, Available at ocess_asof_jun12_2015.pdf. CEC California Interconnection Guidebook: A Guide to Interconnecting Customer-owned Electric Generation Equipment to the Electric Utility Distribution System Using California s Electric Rule 21. Prepared for California Energy Commission. Prepared by Overdomain, LLC, Endecon Engineering, and Reflective Energies. Sep Available at ConEd Handbook of General Requirements for Electrical Service to Dispersed Generation Customers. Consolidated Edison. Specification EO-2115, revision 8. Mar ConEd Distributed Generation Review & Interconnection. Consolidated Edison. Slides, presented by Manuel J Fernandez, Oct. 17, Available at ConEd Synchronous Generation Placement Availability by Region. Accessed Dec. 8, Available at CPUC Renewables Portfolio Standard Quarterly Report, 4th Quarter California Public Utilities Commission. Available at CPUC Decision Adopting Settlement Agreement Revising Distribution Level Interconnection Rules and Regulations Electric Tariff Rule 21 and Granting Motions to Adopt the Utilities Rule 21 Transition Plans. Public Utilities Commission of the State of California. Decision , Sep. 13, Available at DSIRE Interconnection Regulatory Policies, Database of State Incentives for Renewables & Efficiency (DSIRE). NC Clean Energy Technology Center. Available at accessed Oct. 10, FERC Small Generator Interconnection Agreements and Procedures. Federal Energy Regulatory Commission. Order No FERC 61, CFR Part 35. Nov. 22, FERC Order Clarifying Compliance Procedures. Federal Energy Regulatory Commission. Order No. 792-A. 146 FERC 61,214. Mar. 20, Hydro One Technical Interconnection Requirements for Distributed Generation - Micro Generation & Small Generation, 3-phase, Less Than 30 kw. Hydro One Networks Inc DT Available at In%20Tariff/microFIT_TIR_for_Distributed_Generation.pdf. CHP Interconnection Equipment Analysis Page 32

39 Hydro One Distributed Generation Technical Interconnection Requirements Interconnections at Voltages 50 kv and Below. Hydro One Networks Inc. Mar DT R3. Available at Hydro One. 2015a. Hydro One Distributed Generation List of Applications. Available at Hydro One. 2015b. DOM Request. Website. Hydro One Inc. Available at Hydro One. 2015c. Station & Feeder Capacity Calculator. Hydro One Inc. Available at Hydro One. 2015d. List of Station Capacity. Hydro One Inc. Available at Hydro Ottawa Embedded Generation Connection Guideline. Hydro Ottawa. Feb. 2, ECG0006 Rev 1. Available at Manitoba Hydro Technical Requirements for Connecting Distributed Resources to the Manitoba Hydro Distribution System. Jan Available at MPUC Order Establishing Standards, In the Matter of Establishing Generic Standards for Utility Tariffs for Interconnection and Operation of Distributed Generation Facilities under Minnesota Laws 2001, Chapter 212. Minnesota Public Utilities Commission. Docket No. E-999/CI Available at ocumentid={eb5dce72-415a f-35ba37ec59ea}&documenttitle= National Grid Supplement to Specifications for Electrical Installations Requirements for Parallel Generation Connected to a National Grid Owned EPS. National Grid. Electric System Bulletin No. 756, version 2.2. Sep Available at National Grid Network Feeder Navigator. Website, accessed Dec. 8, Available at NYSERDA Interconnection of Distributed Generation in New York State: A Utility Readiness Assessment. Prepared for New York State Energy Research and Development Authority and New York State Department of Public Service by Electric Power Research Institute. Sep Available at Document. NY PSC. 2015a. NY PSC Order, Case 14-M-0101, February 26, NY PSC. 2015b. Standardized Interconnection Requirements and Application Process for New Distributed Generators 2 MW or Less Connected in Parallel with Utility Distribution Systems. New York State PSC. Jul Available at f396b/$FILE/ pdf/Final%20SIR% pdf. CHP Interconnection Equipment Analysis Page 33

40 NY PSC. 2015c. Proposed New York State Standardized Interconnection Requirements and Application Process for New Distributed Generators 5 MW or Less Connected in Parallel with Utility Distribution Systems Redline Version. New York State Public Service Commission. Nov Available at f396b/$FILE/ pdf/SIR%20Revisions%20RL% pdf. NY PSC. 2015d. Equipment Certified Since 2011, and Equipment Certified Prior to Available at Document. NY PSC. 2015e. NYSDPS-DMM: Matter Master In the Matter of SIR Inventory. Available at NYSEG/RGE Requirements for the Interconnection of Generation, Transmission and End-User Facilities. NYSEG/RGE. Bulletin 86-01, Revision Date Oct. 3, Available at Fs%20and%20Docs/Bulletin% pdf. OEB. 2015a. Electricity Distributer Issued Licences. Website. Ontario Energy Board. Available at ity%20distributor. OEB. 2015b. Distribution System Code. Ontario Energy Board. Apr. 15, Available at lines+and+forms#dsc. PG&E Distribution Interconnection Handbook. Pacific Gas and Electric Company. Apr. 2003, with updates in separate files. Available at terconnectionhandbook/index.page. PG&E Wholesale Distribution Tariff (WD Tariff). Pacific Gas and Electric Company. FERC Electric Tariff Volume NO. 4. Oct. 1, Available at n/tariffs/pge_wholesale_distribution_tariff.pdf. PG&E. 2015a. Electric Rule No. 21 Generating Facility Interconnections. Pacific Gas and Electric Company. Jan. 20, Available at PG&E. 2015b. Generate Your Own Power (website). Pacific Gas and Electric Company. Available at PG&E. 2015c. PG&E Wholesale Distribution Queue. Pacific Gas and Electric Company. Spreadsheet. Available at on/publicqueueinterconnection.xls. PG&E. 2015d. Solar Photovoltaic (PV) and Renewable Auction Mechanism (RAM) Program Map. Pacific Gas and Electric Company. Available at ndex.page. CHP Interconnection Equipment Analysis Page 34

41 SaskPower Generation Interconnection Requirements at Voltages 34.5 kv and Below. Mar. 17, Available at SCE Wholesale Distribution Access Tariff. Southern California Edison Company. Docket No. ER FERC Electric Tariff, Second Revised Volume No. 5. Available at SCE The Interconnection Handbook. Southern California Edison Company. Nov. 10, Available at Interconnections/Wholesale-Distribution-Access-Tariff/. SCE Rule 21 Generating Facility Interconnections. Southern California Edison. Jul. 9, Available at SCE. 2015a. Net Energy Metering Interconnection Handbook. Southern California Edison. Jun Available at a195c65fa249/nem_interconnection_handbook.pdf?mod=ajperes. SCE. 2015b. Electrical Service Requirements (ESR). Oct. 23, Available at SCE. 2015c. Grid Interconnections (website). Southern California Edison. Available at Interconnections. SCE. 2015d. Wholesale Distribution Access Tariff (WDAT) and Rule 21 Interconnection Queue. Southern California Edison. Available at SCE. 2015e. DERiM Web Map. ESRI ArcGIS for Southern California Edison. Available at 6b7. USA Congress Energy Policy Act of 2005, Section 1254 Interconnection. Pub. L , 119 Stat (Aug. 8, 2005). Available at 119/pdf/STATUTE-119-Pg594.pdf. Xcel Distribution Generation Guidelines for Customer-Owned Generation. Website. Xcel Energy. Available at ration_guidelines_for_customer-owned_generation_-_mn. CHP Interconnection Equipment Analysis Page 35

42 Appendix A Background and Common Terms Distributed Generation Also: dispersed generation (Con Edison); distributed energy resources; DER; decentralized energy. Distributed generation (DG) resources are spread out across the distribution system, rather than being concentrated at a few points in the transmission system. Onsite Generation Also: Behind-the-meter generation (BtM, BTM, or BTMG); system-side generation; onsite generation (National Grid); embedded generation (Ontario); EG (Ontario). Onsite generation is a type of distributed generation installed in customer facilities on the customer side of the utility meter behind the Point of Common Coupling (PCC) where the utility grid and the customer meet. Often, the power is consumed solely within the customer facility, but in some cases unused power from the generator is exported to the grid. This report focuses on behind-the-meter or onsite generation that operates in parallel with the utility system and therefore must be interconnected to the grid. Electrical Connection Options Standalone Also: isolated operation (SCE); standalone (National Grid). Standalone generators operate in isolation from the utility supply, and thus never operate in parallel with the utility grid. This is common for emergency backup power generators that serve isolated electric circuits when the power grid is offline. Some facilities choose to disconnect from the grid and operate in standalone mode at all times (e.g., many CHP systems in New York State were built as standalone systems before the Standard Interconnection Requirements (SIR) were established in NY). Standalone generation facilities have fewer protection requirements and are not the focus of this report. While standalone generators do not require interconnection agreements, the utility may require approval to ensure they will be isolated from the utility supply at all times. Historically, some utilities have required distances between isolated and grid-connected electrical wiring inside the facility to ensure re-connection of the isolated systems was unlikely. Parallel A generator operates in parallel with the utility grid when it is connected to and operates simultaneously with the utility system. IEEE 1547 s definition of parallel generation is interconnections of 0.1 seconds or longer, while California s (Rule 21) definition is interconnections of more than 60 cycles (one second). Hydro One (Ontario) does not specify a minimum time for an interconnection to be considered parallel. Momentary Parallel Operation Standby generators may need to operate in parallel with the utility power system for a brief period of time while it transitions the load from the utility grid to the generator (or vice versa). This is known as make-before-break load transfer because the distributed generation briefly synchronizes with the utility grid before separating. Fast or quick transfer systems generally make this transition in under 100 milliseconds, while soft load transfer systems may maintain parallel operation for a few seconds, or in the case of Xcel Energy in Minnesota, up to two minutes. In California (Rule 21), momentary parallel operation refers to interconnections of one second (60 cycles) or less. CHP Interconnection Equipment Analysis Page 36

43 Parallel Operation Options Non-Export Non-exporting generators typically operate in parallel with the grid but do not export electricity. The onsite generator is sized and/or controlled to only serve the facility load. In practice, this is achieved with controls that ensure a certain amount of power (kw) is always imported through the meter. This amount of power is referred to as the import setpoint. Often protective relay controls are set with reverse power protection relays that automatically disconnect the generator when power flows backwards through the meter or PCC for more than a few seconds (protective device function 32R). Export Export means that electricity generated in the facility (in excess of the load) is fed backwards through the meter to the utility grid. Depending on the state/province and utility regulations, exported electricity may receive financial compensation through net metering arrangements (at the retail rate) or at the wholesale power rate. When power is exported, a special bi-directional meter is installed that measures both regular (imported) and reverse (exported) electricity flows. Tariff (or Compensation) Options A separate issue from electrical interconnection is how the facility is compensated or charged for electricity when it has an onsite generator. As a result, special tariffs and reimbursement schemes apply to onsite generators, which are defined below. Net Metering Also: net energy metering (California); NEM (California). When power is exported from a facility to the grid, most states and utilities allow for net metering. This is a concept where the customer is reimbursed for exported power at their retail rate. Net metering often applies to certain generation technologies that are deemed beneficial to society, such as power from renewable sources. In this scenario, the exported power often runs the meter backwards when electricity is fed into the grid. The customer receives credits equivalent to reduced usage on their electricity bill for exported power. Unused credits at the end of a billing year may or may not be eligible for payment, and may expire depending on the net metering agreement. Net metering is usually allowed up to certain limits of capacity (limits in state rules generally range between 25 kw and 1,000 kw per site) and/or percentage of the total annual customer usage (commonly %). Feed-in-Tariff Also: FiT; FIT. A feed-in-tariff is similar to net metering, but differs in that electricity from distributed generation receives a certain payment per kwh fed into the grid, which is often above the retail rate. This requires the electricity being fed into the grid to be measured separately with a separate meter. This mechanism is commonly used to spark market uptake of a certain technology. As market uptake increases, the FiT is decreased, and can eventually be replaced by net metering. Wholesale Also: buy back (Con Edison). Exported electricity may be purchased by the interconnected utility or a third-party on the wholesale market, at a wholesale rate. California (Rule 21) refers to a facility that does this as an exporting generating facility. The wholesale rate is generally below the retail rate and any feed-in-tariff rate. If the interconnected utility power is purchased at a fixed, contracted amount, this is commonly referred to as a power purchase agreement or PPA. CHP Interconnection Equipment Analysis Page 37

44 Incidental Export Also: uncompensated generating facility (California Rule 21). Incidental export is when excess electricity is exported to the grid but the customer does not receive compensation for it. Standby Service When onsite generation operates in parallel with the utility, the utility grid may have to provide full power to the facility at times when the onsite generator is unable to operate. In this case, the utility is providing standby service to meet the entire facility load if and when needed. Many utilities require the customer to have standby agreements and/or to pay standby service charges to cover the cost of the utility maintaining its infrastructure (poles wires, transformers, etc.) near the facility to periodically serve this entire load. Types of Generators Synchronous Generators Also: alternators; alternating current (AC) generators. Synchronous generators convert mechanical power to AC electric power. The source of mechanical power a prime mover such as a diesel engine, gas engine, gas-turbine, or steam turbine mechanically rotates the rotor winding, inducing voltages in the outer stator (armature) winding. The voltage generated has a waveform with a frequency that directly corresponds to rotor speed. Synchronous generators have integrated excitation, so they can be run as standalone units in addition to being able to run in parallel with the utility grid (i.e., they are black start capable, in that they can begin to generate electricity without utility grid). The prime mover and generator must be started and brought up to speed, and then it must be synchronized precisely with the utility grid before connection. Table 5 in IEEE gives maximum allowable differences between the generator and utility grid for frequency, phase angle, and voltage magnitude at the moment of connection. If the generator falls out of synchronization with the utility system, it could seriously damage equipment and cause power quality problems on the system. By adjusting excitation levels, the reactive output of the machine can be varied between producing reactive power (appearing capacitive) and consuming reactive power (appearing inductive). Similarly, the power factor of synchronous generators can be controlled from leading (capacitive) to lagging (inductive), allowing voltage regulation and VAR support. Synchronous generators raise greater concern than other types of power generation equipment in synchronism, ground fault, and phase overcurrent protection, and thus may require more advanced protection than induction generators or inverters of the same nameplate capacity. Synchronous generators can contribute greater amounts of fault current for much longer periods. As a result, utilities are more likely to require stability studies for synchronous generators. Induction Generators Also: asynchronous generators. Induction generators also convert mechanical power to AC electric power using the same principles as induction motors. Excitation power is supplied to the stator at the synchronous speed. The prime mover turns the rotor faster than this speed, generating a rotor current with a magnetic field opposing the stator field, causing a stator voltage that pushes current against the applied voltage. Induction generators typically must be grid-connected, so the frequency and voltage is dictated by the electrical grid. Since excitation comes from the grid, black start during a grid outage is not possible. CHP Interconnection Equipment Analysis Page 38

45 Induction generators consume reactive power (and have a lagging power factor) when they draw excitation current from the utility, resulting on voltage drop and increased losses on the utility system. Because of this, correction measures may be needed to return the facility power factor back towards unity. Induction generators have less impact during utility-side faults since they cannot contribute significant amounts of fault current for more than a few cycles. Inverters Also: static power converters (Con Edison); SPC (Con Edison). Inverters use semiconductor components driven by an internal microprocessor to convert direct current (DC) to AC electricity at normal voltages. A rectifier can also be included to convert AC from non-standard voltages and frequencies to DC before the inverter. They are commonly used with DC power sources such as solar photovoltaic arrays, fuel cells, and batteries as well as rotating DC generators on engines, microturbines and wind turbines. More and more, inverters are also used with rotating generators to address utility interconnection issues. Because inverters are a newer technology, national, state, and utility regulations are still developing. The most commonly used standard for inverters is UL Utilities often require proof that inverters are certified to UL 1741 or some equivalent in interconnection applications. UL 1741 also identifies whether an inverter employs active anti-islanding, which the utility may also require. Because inverters use fast-switching solid state, high power, transistors (i.e., thyristors and IGBts) to synthesize the waveform, they are able to respond or stop much more quickly than a rotating machine, so there is less potential for a sustained fault. Inverters typically have embedded protection functions and control systems, and thus smaller, certified units often may not require any additional protection. Grid-tied inverters Also: grid connected inverters; grid tie inverters; synchronous inverters; utility-interconnected inverters Inverters that operate in parallel with the utility grid produce waveforms with voltage, phase angle, and frequency synched to the grid. They also have built-in anti-islanding protection. Grid-tied inverters can be further split into two types: Grid dependent inverters are designed to only operate in parallel with the utility grid; upon loss of grid power, the inverter shuts down to prevent islanding and it does not operate in standalone mode. This type of inverter therefore does not allow the distributed generation to supply electricity to the load in the event of a utility grid outage. Grid-interactive inverters are designed to operate in both parallel and standalone modes, and may require extra protection logic to ensure they do not energize the utility system, and also appropriate synchronization and protection equipment for the transition between operating modes. This type of inverter therefore allows for the distributed generation to continue to supply electricity to the load in the event of a utility grid outage. Standalone inverters that are designed to operate in isolation from the utility grid at all times (i.e., never in parallel mode) do not require synchronization equipment. Some inverters have a soft start up feature which increases power to full output over a few seconds. This feature is desired by utilities because it produces less voltage flicker than suddenly producing at full output. Inverters are usually programmed to operate at a power factor very close to one, but also can be programmed to compensate for other reactive or induction loads and sources on the system. Protective Relays Also: Protection relays A protective relay monitors current, voltage, frequency, or other electric power parameters and detects faults or abnormal conditions by comparing with specified allowable ranges and time periods. When a fault is detected, the CHP Interconnection Equipment Analysis Page 39

46 protective relay sends a control signal to a shunt trip circuit breaker, load break switch, or contactor to trigger it to open. Depending on the fault or issue, the trip command can open a breaker to isolate the generator from the building or isolate the facility from the utility at the PCC. Protective relays were traditionally electromechanical, but nowadays they are more often microprocessor-based. Protective relays measure operating conditions via instrument transformers such as current transformers (CTs) and voltage (or potential) transformers (VTs or PTs). CTs and VTs with proportionally lower currents and voltages, provide protection from the higher currents and voltages in the power system. ANSI/IEEE C37.2 (Standard for Electrical Power System Device Function Numbers, Acronyms, and Contact Designations) assigns standard device numbers and descriptions to protection equipment. The device numbers or functions shaded as blue in Table 19 are most commonly implemented for onsite generation systems. Table 19 Selection of Standard Devices Specified in ANSI/IEEE C37.2 Device No. Function Description 4 Master contactor Makes necessary control circuits to put equipment into operation under desired conditions, and breaks control circuits to take equipment out of operation under undesired conditions. 15 Speed or frequency matching device Matches and holds the machine speed/frequency to that of another system. 21 Distance relay Operates when the admittance, impedance, or reactance of a circuit increases or decreases over set limits. Used to detect faults within a specified line distance. 25 Synchronizing or synchronism check device Allows or causes two systems to be paralleled when they are within desired frequency, phase angle, and voltage limits. 27 Under-voltage relay Operates when the voltage is below a specified value. 32 Power direction relay Also: reverse-power relay; directional power relay; power directional relay; antimotoring. 40 Field relay Also: over/under excitation; loss of excitation; field failure 42 Running circuit breaker Also: contactor 46 Reverse phase current relay/phase balance current relay Also: phase-balance current relay; negative-sequence current relay; phase current imbalance relay; reverse-phase current relay. Operates on power flow in a given direction above a given set point. Used to determine the direction of a fault (upstream or downstream of the relay s location) or the direction of power. When it is anti-motoring, it protects the prime mover by preventing it from being driven as a motor. Operates upon over-excitation (field current exceeds set point), under-excitation (field current below set point), and/or loss of excitation (loss of field current). Used to protect synchronous generators from extensive damage. Connects a machine to its running or operating voltage. May also be used for frequent opening and closing of the breaker by a contactor or other such device, used in series with a circuit breaker or other means of field protection. Operates when currents are unbalanced, have reverse-phase sequence, or have negative-phase sequence components above a defined value. CHP Interconnection Equipment Analysis Page 40

47 Device No. Function Description 47 Phase-sequence voltage relay Also: negative-sequence voltage relay; phase voltage imbalance. 50 Instantaneous overcurrent relay/rate-of-rise relay Also: breaker failure 51 AC time overcurrent relay Also: phase over-current relay; AC inverse time over-current relay; time-delay overcurrent relay. 52 AC circuit breaker Also: AC breaker Operates when voltages are unbalanced, or have negativephase sequence components above a defined value. Operates when the load current exceeds a pickup value, or when there is an excessive rate of current rise, for any amount of time. Operates when the load current exceeds a pickup value for a specified period of time. Commonly 51G (ground time overcurrent relay), 51N (neutral time over-current relay), and 51V (voltage restrained/controlled time over-current). Opens (interrupts) or closes an AC circuit under normal conditions, or opens a circuit under fault or emergency conditions. 59 Over-voltage relay Operates when the voltage is above a specified value. 60 Voltage-balance relay Operates when over a specified difference in voltage between two circuits. 61 Current-balance relay Operates when over a specified difference in current input and output, or between two circuits. 62 Time-delay stopping or opening relay Also: time-delay relay 64 Ground protective relay Also: earth protection relay Delays operation in an automatic sequence initiated by another device. Operates when insulation of a machine, transformer, or other apparatus to ground fails. 67 AC directional-overcurrent relay Operates when AC current is over a specified value in a specified direction. 67V: voltage restrained/controlled directional time overcurrent. 78 Loss of synchronism relay Also: phase-angle measuring protective relay; out-of-step protective relay 79 AC reclosing relay Also: auto-reclose Operates at a specified phase angle between two voltages, between two currents, or between a voltage and a current. Automatically recloses and locks out a circuit interrupter. 81O Over-frequency relay Operates when the frequency is over a specified value. 81U Under-frequency relay Operates when the frequency is below a specified value. 86 Locking-out relay Also: lockout relay Electric tripping relay that typically has to be manually reset. Used to indicate that the system needs to be inspected before reclosing the relay. CHP Interconnection Equipment Analysis Page 41

48 Device No. Function Description 87 Differential protective relay Also: differential relay; current differential relay; differential-protective relay; differential current relay Operates on difference between two currents. Works on Kirchoff s current law (The sum of currents entering and leaving a point is zero). 89 Line switch Electrically operated disconnecting, load-interrupting, or isolating switch. 90 Regulating device Regulates a quantity (e.g., voltage, current, power, speed, frequency, temperature, or load), maintaining a certain value or keeping it between certain limits. 94 Tripping relay Also: trip-free relay Trips a circuit breaker, contactor, or equipment; permits other devices to perform intermediate tripping; or prevents automatically opened circuit interrupters from automatically reclosing. Instrument Transformers Instrument transformers such as current transformers (CT) and voltage (potential) transformers (VT or PT) precisely step down alternating currents and voltages in the secondary winding in a way that is directly proportional to the primary signal; the secondary signals can then be safely used in a protective relay cabinet. Utilities sometimes place response and accuracy requirements on CTs and VTs when used for protective relays with onsite generation. Because facility transformer connections can distort voltages, utilities sometimes require that measurements for system over- and under-voltages be located on the primary side of the facility transformers, especially for larger generators. Utility-grade Relay Some utilities state requirements for utility-grade relays, sometimes for smaller generators but more frequently for larger generators. This is not a consistent or well-defined term, but in general it means they must meet ANSI/IEEE standards C37.90, C , and C CHP Interconnection Equipment Analysis Page 42

49 Direct Transfer Trip A direct transfer trip (DTT) sends a trip signal from a remote location through a dedicated telephone line, fiber optic cable, or radio frequency. For example, if a fault is detected on the substation feeder, the DTT can communicate the trip signal to the location of a distributed generator, tripping the generator breaker. It is often required for larger generators, where it adds another level of redundancy to islanding protection. Adding a DTT to a distributed generation system increases the overall project cost, particularly where multiple trigger points are required. Isolation and Protection Devices Isolation of the distributed generation equipment from the utility power system is required when: maintenance is performed on customer circuits or equipment, there is a fault in utility power service or utility power service is not present (islanding), and the distributed generation equipment is operating in isolation from the grid. Three common types of isolation devices are the disconnect switch, load break switch, and shunt trip circuit breaker. A key difference between these is whether the device is designed to switch a line with no current, or if it can open or close line with full-current, or in the worst case during fault conditions. Disconnect Switch Also: disconnector; disconnecting switch; isolator switch; isolator; isolating switch. A disconnect switch is a two-position switch (open/closed) used to ensure electrical circuits are isolated during service or maintenance for worker safety. Disconnectors lack a mechanism to suppress electric arcs which can occur when a live circuit is switched off, so they are designed to be opened after the current has been interrupted by another control device, such as a circuit breaker. The main functions of the disconnect switch are to carry load currents continuously without overheating, open and close reliably, and isolate the load when open. It is typically manually operated (though it may have a motor for remote system control), and lockable in the open position so that inadvertent operation cannot be made for extra safety. Three-phase connections may have a common operating handle, but at higher voltages it is more commonly required that each phase has a separate handle or lever. In distributed generation, a disconnect switch is normally required at the generating equipment. The disconnect switch must be accessible to utility personnel and have provisions for a padlock so it can be locked in the open position (locked out). When disconnecting the distributed generator from the customer load, it is sometimes called a DG source disconnect, and when disconnecting the distributed generator from the utility distribution system, it is sometimes called a DG system disconnect or DG utility disconnect. (ESA - Canada) A disconnect switch can be integrated within the breaking chamber of a circuit breaker, and then it is called a disconnecting circuit breaker. If a system has two disconnects that are never allowed to be closed at the same time, a kirk-key system is used. This approach is often used to manually change a generator from the grid-connected to grid-isolated mode. The only way to close the disconnect switch is to use the kirk-key. To change modes the first disconnect must be opened and the key can then be used to close the other disconnect. Load Break Switch Also: LBS; load switch; switch; load break disconnect switch. A load break switch is a disconnect switch that can make and break (close and open) specified currents under normal operating conditions. This is accomplished by using different contacts, increased switching speed, and having a chamber capable of interrupting arcs safely and reliably. A load break switch is not designed to be used to interrupt CHP Interconnection Equipment Analysis Page 43

50 a circuit during fault conditions. Load break switches are generally operated manually, though they can sometimes be operated with electrical tripping. Circuit Breaker A circuit breaker is a mechanical/thermal switching device that is designed to break the circuit when specified current levels are exceeded for a certain time (i.e., abnormal conditions). A shunt trip breaker can also be commanded open in response to a control signal (i.e., from a protective relay). Some devices can also close or remake the connection based on a separate control signal. When a protection relay detects a fault condition, it sends a trip signal that automatically triggers the circuit breaker to open. Mechanical energy, such as springs or compressed air, separates the contacts, opening the breaker. Unlike a fuse, it can be reset (or closed) manually or automatically by electric motors in larger units. Circuit breakers are preferred over load break switches for highly capacitive currents (as in long cables and lines) and for reactive loads (such as large transformers). A disconnect switch can be integrated within the breaking chamber of a circuit breaker, and then it is called a disconnecting circuit breaker. This device eliminates the need for separate disconnectors, which is desirable because of decreased physical space requirements, increased reliability, and decreased time offline since open-air disconnection switches require more frequent maintenance. When used to break an interconnection, for example at the point of common coupling between the customer and the utility distribution system, a circuit breaker is sometimes referred to as an intertie breaker (Con Edison). Hydro Ontario refers to two types of interrupters or interrupting devices. When on the customer side of the transformer, it is a low voltage interrupter (LVI), and when on the utility side of the transformer, it is a high voltage interrupter (HVI) (though it may still be at low or medium voltage). These devices must be able to interrupt the maximum fault current. Contactor A contactor is an electrically controlled relay designed to switch high-power circuits. It has a higher current rating than other relays and can often switch multiple phases, and as such is designed for direct connection to high current load devices. Contactors are not intended to interrupt a circuit under abnormal conditions, such as a short circuit current. The contacts are normally open, so that the switch opens when the coil is de-energized. Direct Transfer Trip A direct transfer trip (DTT) communicates a trip signal to (or from) a device at a remote location. For example, if a substation relay detects a fault on the feeder, the DTT sends a trip signal to the location of the distributed generator, triggering the distributed generation breaker directly or to the protective relay. The communication can be through telephone lines, a dedicated fiber, or radio. Transformers Transformers can be located on either the customer-side or the utility-side of the point of common coupling. Transformers step down the voltage from distribution levels (e.g., 13.2kV or 4,160 volts) to common voltage levels for use within the facility (600, 480, or 208 volts). Inside the facility there can also be additional transformers to further step down voltages (for instance from 480 volts to 208/120 volts). Three-phase transformers are wired in either a wye or delta configuration. The utility can specify winding configurations and grounding requirements for the transformer depending on local system requirements and the type of transformer. Utilities may also require a dedicated transformer be added between the onsite generator and the facility to provide additional fault isolation. CHP Interconnection Equipment Analysis Page 44

51 Electrical Standards As interconnection of distributed generation with the power system is relatively new, many of the standards are still evolving. It is common for standard interconnection requirements to simply state that the most recent version of a standard applies. Bodies that develop relevant industry standards include: ANSI American National Standards Institute CSA Canadian Standards Association IEC International Electrotechnical Commission IEEE Institute of Electrical and Electronics Engineers UL (previously known as Underwriters Laboratories) Commonly referenced standards are described in Table 20. Standards highlighted as blue are most commonly referenced. Table 20 Commonly Referenced Standards in Standard Interconnection Requirements Standard Full Name Description ANSI C84.1 ANSI/IEEE 446 CSA 22.2 No CAN/CSA 22.2 No. 257 CAN/CSA C22.3 No CAN3- C Electric Power Systems and Equipment Voltage Ratings (60 Hertz) Recommended Practice for Emergency and Standby Power Systems for Industrial and Commercial Power Systems Green Book General Use Power Supplies Interconnecting Inverter- Based Micro-Distributed Resources to Distribution Systems Interconnection of Distributed Resources and Electricity Supply Systems Preferred Voltage Levels for AC Systems, 0 to 50,000 V Nominal voltage ratings and operating tolerances Preferred voltage ratings 100 V to 12,000 kv Uses, power sources, design, and maintenance of emergency and standby power systems Standard for AC and DC type power supplies Utility-interconnected inverters covered in Clause 15 Electrical requirements for interconnection of micro inverter DG systems to low voltage systems (up to 600 V) Minimum technical requirements for interconnection of DG with power distribution systems up to 50 kv Covers DG technologies up to 10 MW at PCC Covers inverter interconnections at medium voltage Covers generator interconnections at low or medium voltage For safety of persons, continuity of service, and protection of property Voltage standards for AC systems in Canada CHP Interconnection Equipment Analysis Page 45

52 Standard Full Name Description CAN/CSA- C IEEE 100 IEEE 1547 IEEE IEEE 519 IEEE C57.13 IEEE C IEEE C62.45 IEEE/ANSI C37.2 Instrument Transformers Part 6: Requirements for Protective Current Transformers for Transient Performance The Authoritative Dictionary of IEEE Standards Terms Standard for Interconnecting Distributed Resources with Electric Power Systems Standard Conformance Test Procedures for Equipment Interconnecting Distributed Resources with Electric Power Systems Recommended Practice and Requirements for Harmonic Control in Electric Power Systems Standard Requirements for Instrument Transformers Recommended Practice on Characterization of Surges in Low Voltage (1000 V and Less) AC Power Circuits Recommended Practice on Surge Testing for Equipment Connected to Low Voltage (1000 V and Less) AC Power Circuits Standard Electrical Power System Device Function Numbers, Acronyms, and Contact Designations Applies to inductive current transformers for transient performance applications Requirements and tests Definitions of electrical and electronic terms used in IEEE standards Electrical requirements at PCC for interconnection of DG with electric power systems Technical specifications: performance, operation, testing, safety considerations, maintenance Focuses on connections with radial primary and secondary distribution systems (does consider network systems) Testing procedures to ensure functions and equipment conform to IEEE 1547 Type, production, and commissioning tests Recommended practice to reduce interference between electrical equipment Describes voltage and current waveforms, and waveform distortion goals Electrical, dimensional, and mechanical characteristics For current and inductive voltage transformers Test code Characterizes the surge environment at locations on AC power circuits Recommendations for surge testing using recommended test waveforms in C Defines device and function numbers and acronyms for use in electrical substations, generating plants, and power utilization and conversion apparatus Discusses purpose and use of numbers and acronyms CHP Interconnection Equipment Analysis Page 46

53 Standard Full Name Description IEEE/ANSI C37.90 Standard for Relays and Relay Systems Associated with Electric Power Apparatus Basis for design and evaluation of relays and relay systems Applies to relays for power protection and control Service conditions, electrical ratings, thermal ratings, and testing requirements IEEE/ANSI C IEEE/ANSI C NEC NESC/ANSI C2 UL 1741 Standard Surge Withstand Capability (SWC) Tests for Relays and Relay Systems Associated with Electric Power Apparatus Standard for Withstand Capability for Relay Systems to Radiated Electromagnetic Interference from Transceivers National Electrical Code (National Fire Protection Association) National Electrical Safety Code Standard for Inverters, Converters, Controllers and Interconnection System Equipment for Use with Distributed Energy Resources SWC design tests for relays and relay systems Test procedures, generator characteristics, waveforms, criteria, and documentation Design tests for relays and relay systems on radiated electromagnetic interference from transceivers. Field strength, test frequencies, modulation, sweep rates, equipment setup/connection, test procedures, criteria, documentation Standards to safely install electrical wiring and equipment in the US Safety of persons during installation, operation, and maintenance of electric power and communication utility systems Interconnection equipment requirements Covers inverters, converters, charge controllers, and other equipment Covers both standalone and grid-connected equipment CHP Interconnection Equipment Analysis Page 47

54 Appendix B Common Utility Concerns with Electrical Interconnection Utility Distribution Systems Traditionally, utility grids were designed for power flow from centralized generators through high-voltage transmission lines, converted in substations to medium voltage for the primary distribution system feeders (Con Edison calls this high tension ), and stepped down again through transformers to the secondary distribution system (Con Edison calls this low tension ) which delivers power to customers. The transformer can be owned by either the utility or the customer. Secondary distribution is generally at 480 or 208 volts in the U.S. and can be 600 volts in Canada. Some very large customers can receive power at primary distribution voltages (e.g., 4,160 volts or 13.2 kv) from multiple feeders. The most common configurations for secondary distribution systems are radial and network. Radial Distribution System In a radial distribution system, primary lines radiate from the substation to transformers, and secondary lines radiate from the transformers to the customers. This system is designed for electricity to flow in one direction from the substation to the customers. While cost-effective to build, a power failure or short circuit interrupts power for all customers on that line. As a result, islanding can more easily occur in radial distribution systems. Figure 4 - Radial Distribution System (Modified from CEC 2003 and ConEd 2012) CHP Interconnection Equipment Analysis Page 48

55 Network Distribution System A secondary network distribution system (also: multiple source system, Hydro One; low voltage network, Con Edison) is common in high load density municipal or downtown areas. Network systems include area networks also referred to as grid networks (Rule 21) or street networks that can supply multiple blocks of buildings, and spot networks that supply one or two buildings. These systems have multiple feeders serving the low voltage network. Because of this, customers continue to receive power if one feeder goes down. Network protectors prohibit power to flow from the network back to the substation feeders, which limits the amount of distributed generation that can be installed within a network. Figure 5 Network Distribution System (Modified from CEC 2003 and ConEd 2012) Protection Needs for Distributed Generation Protection devices protect utility-side equipment from short circuits and abnormal operating conditions. Utilities specify customer side protection devices to ensure that (a) distributed generation does not energize a de-energized grid, and (b) the power generated onsite is consistent with the supply from the utility power system. The goal is to minimize any potential detrimental impact the DG system might have on the utility grid and on other nearby customers. Utility interconnection requirements for onsite generation are primarily concerned with protecting equipment on the utility system from damage, as well as any limiting and liability for damage at nearby customer facilities. They are not concerned with protecting the generator owner s equipment. Several specific utility concerns are addressed below. CHP Interconnection Equipment Analysis Page 49